QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM
TO
.

Commission file number 1-31447

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas
(State or other jurisdiction of incorporation or organization)

74-0694415
(I.R.S. Employer Identification No.)

1111 Louisiana
Houston, Texas 77002

(713) 207-1111

(Address and zip code of principal executive offices)

(Registrants telephone number, including area code
)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes
þ
No
o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer
þ

Accelerated filer
o

Non-accelerated filer
o

Smaller reporting company
o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes
o
No
þ

As of March 31, 2008, CenterPoint Energy, Inc. had 328,265,076 shares of common stock
outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2008

From time to time we make statements concerning our expectations, beliefs, plans, objectives,
goals, strategies, future events or performance and underlying assumptions and other statements
that are not historical facts. These statements are forward-looking statements within the meaning
of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from
those expressed or implied by these statements. You can generally identify our forward-looking
statements by the words anticipate, believe, continue, could, estimate, expect,
forecast, goal, intend, may, objective, plan, potential, predict, projection,
should, will, or other similar words.

We have based our forward-looking statements on our managements beliefs and assumptions based
on information available to our management at the time the statements are made. We caution you that
assumptions, beliefs, expectations, intentions and projections about future events may and often do
vary materially from actual results. Therefore, we cannot assure you that actual results will not
differ materially from those expressed or implied by our forward-looking statements.

The following are some of the factors that could cause actual results to differ materially
from those expressed or implied in forward-looking statements:



the resolution of the true-up proceedings, including, in particular, the results of
appeals to the courts regarding rulings obtained to date;



state and federal legislative and regulatory actions or developments, including
deregulation, re-regulation, environmental regulations, including regulations related to
global climate change, and changes in or application of laws or regulations applicable to
the various aspects of our business;



timely and appropriate rate actions and increases, allowing recovery of costs and a
reasonable return on investment;



cost overruns on major capital projects that cannot be recouped in prices;



industrial, commercial and residential growth in our service territory and changes in
market demand and demographic patterns;



the timing and extent of changes in commodity prices, particularly natural gas;



the timing and extent of changes in the supply of natural gas;



the timing and extent of changes in natural gas basis differentials;



weather variations and other natural phenomena;



changes in interest rates or rates of inflation;



commercial bank and financial market conditions, our access to capital, the cost of such
capital, and the results of our financing and refinancing efforts, including availability
of funds in the debt capital markets;



actions by rating agencies;



effectiveness of our risk management activities;



inability of various counterparties to meet their obligations to us;



non-payment for our services due to financial distress of our customers, including
Reliant Energy, Inc. (RRI);



the ability of RRI and its subsidiaries to satisfy their other obligations to us,
including indemnity obligations, or in connection with the contractual arrangements
pursuant to which we are their guarantor;

our potential business strategies, including acquisitions or dispositions of assets or
businesses, which we cannot assure will be completed or will have the anticipated benefits
to us;



acquisition and merger activities involving us or our competitors; and



other factors we discuss in Risk Factors in Item 1A of Part I of our Annual Report on
Form 10-K for the year ended December 31, 2007, which is incorporated herein by reference,
and other reports we file from time to time with the Securities and Exchange Commission.

You should not place undue reliance on forward-looking statements. Each forward-looking
statement speaks only as of the date of the particular statement.

General.
Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy,
Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed
Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint
Energy, or the Company). The Interim Condensed Financial Statements are unaudited, omit certain
financial statement disclosures and should be read with the Annual Report on Form 10-K of
CenterPoint Energy for the year ended December 31, 2007 (CenterPoint Energy Form 10-K).

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the
electric transmission and distribution business in a 5,000-square mile area of the Texas
Gulf Coast that includes Houston; and

Basis of Presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at
the date of the financial statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

The Companys Interim Condensed Financial Statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the financial position, results
of operations and cash flows for the respective periods. Amounts reported in the Companys
Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for
a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand
for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance
and other expenditures and (d) acquisitions and dispositions of businesses, assets and other
interests.

For a description of the Companys reportable business segments, reference is made to Note 13.

(2) New Accounting Pronouncements

In April 2007, the Financial Accounting Standards Board (FASB) issued Staff Position No. FIN
39-1, Amendment of FASB Interpretation No. 39, (FIN 39-1) which permits companies that enter into
master netting arrangements to offset cash collateral receivables or payables with net derivative
positions under certain circumstances. The Company adopted FIN 39-1 effective January 1, 2008 and
began netting the cash collateral receivables and payables and also its derivative assets and
liabilities with the same counterparty subject to master netting agreements.

In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159,
The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of
FASB Statement No. 115 (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified
election dates, to measure eligible items at fair value (the fair value option). The Company
would report unrealized gains and losses on items for which the fair value option has been elected
in earnings at each subsequent reporting period. This accounting

standard is effective as of the beginning of the first fiscal year that begins after
November 15, 2007 but is not required to be applied. The Company currently has no plans to apply
SFAS No. 159.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007),

Business Combinations (SFAS
No. 141R)
.
SFAS No. 141R will significantly change the accounting for business combinations. Under
SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and
liabilities assumed in a transaction at the acquisition date fair value with limited exceptions.
SFAS No. 141R also includes a substantial number of new disclosure requirements and applies
prospectively to business combinations for which the acquisition date is on or after the beginning
of the first annual reporting period beginning on or after December 15, 2008. As the provisions of
SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until
applicable transactions occur.

In December 2007, the FASB issued SFAS No. 160,

Noncontrolling Interests in Consolidated
Financial Statements  An Amendment of ARB No. 51 (SFAS No. 160). SFAS No. 160 establishes new
accounting and reporting standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. This accounting standard is effective for fiscal years, and
interim periods within those fiscal years, beginning on or after December 15, 2008. The Company
will adopt SFAS No. 160 as of January 1, 2009. The Company expects that the adoption of SFAS No.
160 will not have a material impact on its financial position, results of operations or cash flows.

Effective January 1, 2008, the Company adopted SFAS No. 157, Fair Value Measurements (SFAS
No. 157), which requires additional disclosures about the Companys financial assets and
liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective
date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized
or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and
interim periods within those fiscal years, beginning after November 15, 2008. As defined in SFAS
No. 157, fair value is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the measurement date. Where
available, fair value is based on observable market prices or parameters or derived from such
prices or parameters. Where observable prices or inputs are not available, valuation models are
applied. These valuation techniques involve some level of management estimation and judgment, the
degree of which is dependent on the price transparency for the instruments or market and the
instruments complexity for disclosure purposes. Beginning in January 2008, assets and liabilities
recorded at fair value in the Condensed Consolidated Balance Sheet are categorized based upon the
level of judgment associated with the inputs used to measure their value. Hierarchical levels, as
defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the
inputs to fair valuations of these assets and liabilities, are as follows:

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or
liability, either directly or indirectly. Level 2 inputs include quoted prices for similar
instruments in active markets, and inputs other than quoted prices that are observable for the
asset or liability. Fair value assets and liabilities that are generally included in this
category are derivatives with fair values based on inputs from actively quoted markets.

Level 3: Inputs are unobservable inputs for the asset or liability, and include situations
where there is little, if any, market activity for the asset or liability. In certain cases, the
inputs used to measure fair value may fall into different levels of the fair value hierarchy. In
such cases, the level in the fair value hierarchy within which the fair value measurement in its
entirety falls has been determined based on the lowest level input that is significant to the
fair value measurement in its entirety. The Companys assessment of the significance of a
particular input to the fair value measurement in its entirety requires judgment, and considers
factors specific to the asset. Generally, assets and liabilities carried at fair value and
included in this category are financial derivatives.

The following table presents information about the Companys assets and liabilities (including
derivatives that are presented net) measured at fair value on a recurring basis as of March 31,
2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to
determine such fair value.

Amounts represent the impact of legally enforceable master netting agreements that
allow the Company to settle positive and negative positions and also cash collateral held
or placed with the same counterparties.

The following table presents additional information about assets or liabilities, including
derivatives that are measured at fair value on a recurring basis for which the Company has utilized
Level 3 inputs to determine fair value, for the three months ended March 31, 2008:

Fair Value Measurements

Using Significant

Unobservable Inputs

(Level 3)

Derivatives, net

(in millions)

Beginning balance as of January 1, 2008

$

(3

)

Total gains or losses (realized and unrealized):

Included in earnings

6

Included in other comprehensive loss



Net transfers into level 3



Purchases, sales, other settlements, net

(1

)

Ending balance as of March 31, 2008

$

2

The amount of total gains or losses for the period
included in earnings attributable to the change in
unrealized gains or losses relating to assets
still held at the reporting date

$

1

(3) Employee Benefit Plans

The Companys net periodic cost includes the following components relating to pension and
postretirement benefits:

The Company expects to contribute approximately $8 million to its pension plans in 2008, of
which $2 million had been contributed as of March 31, 2008.

The Company expects to contribute approximately $21 million to its postretirement benefits
plan in 2008, of which $6 million had been contributed as of March 31, 2008.

(4) Regulatory Matters

(a) Recovery of True-Up Balance

In March 2004, CenterPoint Houston filed its true-up application with the Public Utility
Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding
interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In
December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing
CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included
interest through August 31, 2004, and provided for adjustment of the amount to be recovered to
include interest on the balance until recovery, along with the principal portion of additional
excess mitigation credits (EMCs) returned to customers after August 31, 2004 and in certain other
respects.

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court
in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In
its judgment, the district court:



reversed the Texas Utility Commissions ruling that had denied recovery of a portion of
the capacity auction true-up amounts;



reversed the Texas Utility Commissions ruling that precluded CenterPoint Houston from
recovering the interest component of the EMCs paid to retail electric providers; and



affirmed the True-Up Order in all other respects.

The district courts decision would have had the effect of restoring approximately
$650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from
CenterPoint Houstons initial request.

CenterPoint Houston and other parties appealed the district courts judgment to the Texas
Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of
appeals:



reversed the district courts judgment to the extent it restored the capacity auction
true-up amounts;



reversed the district courts judgment to the extent it upheld the Texas Utility
Commissions decision to allow CenterPoint Houston to recover EMCs paid to Reliant Energy,
Inc. (RRI);



ordered that the tax normalization issue described below be remanded to the Texas Utility
Commission as requested by the Texas Utility Commission; and



affirmed the district courts judgment in all other respects.

CenterPoint Houston and two other parties filed motions for rehearing with the court of
appeals. On April 17, 2008, the court of appeals denied those motions and reissued substantially
the same opinion as it had rendered in December 2007. CenterPoint Houston now plans to seek
further review by the Texas Supreme Court. Although the Company and CenterPoint Houston believe
that CenterPoint Houstons true-up request is consistent with applicable statutes and regulations
and, accordingly, that it is reasonably possible that it will be successful in its further appeal,
the Company can provide no assurance as to the ultimate court rulings on the issues to be
considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission
on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005 the Company recorded a net
after-tax extraordinary loss of $947 million. No amounts related to the district courts judgment
or the decision of the court of appeals have been recorded in the Companys consolidated financial
statements. However, if the court of appeals

decision is not reversed or modified as a result of further review by the Texas Supreme Court,
the Company anticipates that it would be required to record an additional loss to reflect the court
of appeals decision. The amount of that loss would depend on several factors, including ultimate
resolution of the tax normalization issue described below and the calculation of interest on any
amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the
amounts recorded based on the True-up Order, but could range from $130 million to $350 million plus
interest subsequent to December 31, 2007.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houstons stranded cost
recovery by approximately $146 million, which was included in the extraordinary loss discussed
above, for the present value of certain deferred tax benefits associated with its former electric
generation assets. The Company believes that the Texas Utility Commission based its order on
proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 which would have
allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive
election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess
Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew
those proposed normalization regulations and in March 2008 adopted final regulations that would not
permit CenterPoint Houston to pass the tax benefits back to customers without creating
normalization violations. In addition, the Company received a Private Letter Ruling (PLR) from the
IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas
Utility Commissions order reducing CenterPoint Houstons stranded cost recovery by $146 million
for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commissions order relating to the ADITC reduction is not reversed or
otherwise modified on remand so as to eliminate the normalization violation, the IRS could require
the Company to pay an amount equal to CenterPoint Houstons unamortized ADITC balance as of the
date that the normalization violation is deemed to have occurred. In addition, the IRS could deny
CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the
taxable year that the normalization violation is deemed to have occurred. Such treatment, if
required by the IRS, could have a material adverse impact on the Companys results of operations,
financial condition and cash flows in addition to any potential loss resulting from final
resolution of the True-Up Order. However, the Company and CenterPoint Houston will continue to
pursue a favorable resolution of this issue through the appellate or administrative process.
Although the Texas Utility Commission has not previously required a company subject to its
jurisdiction to take action that would result in a normalization violation, no prediction can be
made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the
Texas Utility Commissions True-Up Order to be recovered either through the issuance of transition
bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a
financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis
County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in
transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging
from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston
recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus
interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing
it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over
14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized
CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the
true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint
Houston to collect approximately $24 million of rate case expenses over three years without a
return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and
Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return
on the CTC portion of the true-up balance was included in CenterPoint Houstons tariff-based
revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the
unrecovered balance of the CTC was reduced from 11.075% to a weighted average cost of capital of
8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the
district court issued a judgment reversing the CTC Order in three respects. First, the court ruled
that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the
interest rate applicable to CTC

amounts. The district court reached that conclusion based on its belief that the Texas Supreme
Court had previously invalidated that entire section of the rule. The 11.075% interest rate in
question was applicable from the implementation of the CTC Order on September 13, 2005 until
August 1, 2006, the effective date of the implementation of a new CTC in compliance with the
revised rule discussed above. Second, the district court reversed the Texas Utility Commissions
ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately
$5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation
of electric generation assets. Finally, the district court accepted the contention of one party
that the CTC should not be allocated to retail customers that have switched to new on-site
generation. The Texas Utility Commission and CenterPoint Houston disagree with the district courts
conclusions and, in May 2006, appealed the judgment to the Texas Third Court of Appeals, and if
required, CenterPoint Houston plans to seek further review from the Texas Supreme Court. All briefs
in the appeal have been filed, and oral arguments were held in December 2006. The ultimate outcome
of this matter cannot be predicted at this time. However, the Company does not expect the
disposition of this matter to have a material adverse effect on the Companys or CenterPoint
Houstons financial condition, results of operations or cash flows.

During the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized
approximately $11 million and $5 million, respectively, in operating income from the CTC, which was
terminated in February 2008 when the transition bonds described below were issued. Additionally,
during the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized approximately
$3 million and $2 million, respectively, of the allowed equity return not previously recorded.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the
types of true-up balances that can be securitized by utilities and authorized the issuance of
transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a
request with the Texas Utility Commission for a financing order that would allow the securitization
of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit
costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston
reached substantial agreement with other parties to this proceeding, and a financing order was
approved by the Texas Utility Commission in September 2007. In February 2008, a new special
purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds
pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final
maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the
issuance of those bonds, the CTC was terminated and a transition charge was implemented.

As of March 31, 2008, the Company had not recorded an allowed equity return of $218 million on
CenterPoint Houstons true-up balance because such return will be recognized as it is recovered in
rates.

(b) Rate Cases

Texas.
In March 2008, CERC Corp.s natural gas distribution business (Gas Operations) filed a
request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47
cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers
in cities and communities on the outskirts of Houston. The request seeks to establish uniform
rates, charges and terms and conditions of service for the cities and environs of the Texas Coast
service territory. The effect of the requested rate changes will be to increase the Texas Coast
service territorys revenues by approximately $7 million per year.

Minnesota.
In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a
request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to
recover approximately $21 million in unrecovered purchased gas costs related to periods prior to
July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously
approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations
recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and
reduced the regulatory asset related to these costs by an equal amount. In March 2007, following
the MPUCs denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court
of Appeals for review of the MPUCs decision. That court heard oral arguments on the appeal in
February 2008 and is expected to render its decision within 90 days of that hearing. No prediction
can be made as to the ultimate outcome of this matter.

The Company is exposed to various market risks. These risks arise from transactions entered
into in the normal course of business. The Company utilizes derivative instruments such as physical
forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather
and interest rates on its operating results and cash flows.

(a) Non-Trading Activities

Cash Flow Hedges.
The Company has entered into certain derivative instruments that qualify as
cash flow hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities
(SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated
with natural gas purchases and sales to reduce cash flow variability related to meeting the
Companys wholesale and retail customer obligations. During each of the three months ended March
31, 2007 and 2008, hedge ineffectiveness resulted in a loss of less than $1 million from
derivatives that qualify for and are designated as cash flow hedges. No component of the derivative
instruments gain or loss was excluded from the assessment of effectiveness. If it becomes probable
that an anticipated transaction being hedged will not occur, the Company realizes in net income the
deferred gains and losses previously recognized in accumulated other comprehensive loss. When an
anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss
recognized in accumulated other comprehensive loss is reclassified and included in the Statements
of Consolidated Income under the Expenses caption Natural gas. Cash flows resulting from these
transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash
Flows in the same category as the item being hedged. As of March 31, 2008, the Company expects
$2 million ($1 million after-tax) in accumulated other comprehensive income to be reclassified as a
decrease in Natural gas expense during the next twelve months.

The length of time the Company is hedging its exposure to the variability in future cash flows
using derivative instruments that have been designated and have qualified as cash flow hedging
instruments is less than one year. The Companys policy is not to exceed ten years in hedging its
exposure.

Hedging of Future Debt Issuances.
As of March 31, 2008, the Company had outstanding treasury
rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300
million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year
debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate
expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008,
as changes in the U.S treasury rate would cause variability in the Companys forecasted interest
payments. These treasury rate locks qualify as cash flow hedges under SFAS No. 133. Accordingly,
unrealized gains and losses associated with the treasury rate locks are recorded as a component of
accumulated other comprehensive loss. The realized gain or loss recognized upon settlement of the
treasury rate locks will be initially recorded as a component of accumulated other comprehensive
loss and will be recognized as a component of interest expense over the life of the related
financing arrangement. During the three months ended March 31, 2008, the Company recognized a $14
million loss ($9 million after-tax) for these treasury rate locks in other comprehensive loss.
Ineffectiveness for the treasury rate locks was not material during the three months ended March
31, 2008.

Other Derivative Instruments.
The Company enters into certain derivative instruments to
manage physical commodity price risks that do not qualify or are not designated as cash flow or
fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage
physical commodity price risks and does not engage in proprietary or speculative commodity trading.
During the three months ended March 31, 2007 and 2008, the Company recognized unrealized net losses
of $8 million and $22 million, respectively. During the three months ended March 31, 2007, the
unrealized net losses are included in the Statements of Consolidated Income under the Expenses
caption Natural Gas. During the three months ended March 31, 2008, unrealized net losses of $20
million are included in the Statements of Consolidated Income under the Revenues caption and
unrealized net losses of $2 million are included in the Statements of Consolidated Income under the
Expenses caption Natural Gas.

Weather Derivatives.
The Company has weather normalization or other rate mechanisms that
mitigate the impact of weather in certain of its Gas Operations jurisdictions. The remaining Gas
Operations jurisdictions,

Minnesota, Mississippi and Texas, do not have such mechanisms. As a result, fluctuations from
normal weather may have a significant positive or negative effect on the results of these
operations.

In 2007, the Company entered into heating-degree day swaps to mitigate the effect of
fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter
heating season. The swaps are based on ten-year normal weather and provide for a maximum payment
by either party of $18 million. During the three months ended March 31, 2008, the Company
recognized an $11 million loss ($7 million after-tax) related to these swaps. This was offset in
part by increased revenues due to colder than normal weather.

Embedded Derivative.
The Companys 3.75% convertible senior notes contain contingent interest
provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133,
and accordingly, must be split from the host instrument and recorded at fair value on the balance
sheet. The value of the contingent interest component was not material at issuance or at March 31,
2008.

(6) Goodwill

Goodwill by reportable business segment as of both December 31, 2007 and March 31, 2008 is as
follows (in millions):

Natural Gas Distribution

$

746

Interstate Pipelines

579

Competitive Natural Gas Sales and Services

335

Field Services

25

Other Operations

11

Total

$

1,696

(7) Comprehensive Income

The following table summarizes the components of total comprehensive income (net of tax):

For the Three Months Ended

March 31,

2007

2008

(in millions)

Net income

$

130

$

123

Other comprehensive income (loss):

SFAS No. 158 adjustment (net of tax of $1 and $1)

2

2

Net deferred loss from cash flow hedges (net of tax of $5)



(9

)

Reclassification of deferred gain from cash flow hedges
realized in net income (net of tax of $14 and $2)

(22

)

(4

)

Other comprehensive loss

(20

)

(11

)

Comprehensive income

$

110

$

112

The following table summarizes the components of accumulated other comprehensive loss:

December 31,

March 31,

2007

2008

(in millions)

SFAS No. 158 adjustment

$

(48

)

$

(46

)

Net deferred gain (loss) from cash flow hedges

4

(9

)

Total accumulated other comprehensive loss

$

(44

)

$

(55

)

(8) Capital Stock

CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of
1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value
preferred stock. At December 31, 2007, 322,718,951 shares of CenterPoint Energy common stock were
issued and 322,718,785 shares of CenterPoint Energy common stock were outstanding. At March 31,
2008, 328,265,242 shares of CenterPoint Energy common

stock were issued and 328,265,076 shares of CenterPoint Energy common stock were outstanding.
See Note 9(b) describing the conversion of the 3.75% Convertible Senior Notes in the first quarter
of 2008. Outstanding common shares exclude 166 treasury shares at both December 31, 2007 and March
31, 2008.

(9) Short-term Borrowings and Long-term Debt

(a) Short-term Borrowings

In October 2007, CERC amended its receivables facility and extended the termination date
to October 28, 2008. The facility size will range from $150 million to $375 million during the
period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the
facility was designed to track the seasonal pattern of receivables in CERCs natural gas
businesses. At March 31, 2008, the facility size was $375 million. As of December 31, 2007 and
March 31, 2008, $232 million and $200 million, respectively, was advanced for the purchase of
receivables under CERCs receivables facility.

(b) Long-term Debt

Revolving Credit Facilities.
As of March 31, 2008, the Company had no borrowings,
approximately $28 million of outstanding letters of credit and no commercial paper outstanding
under its $1.2 billion credit facility. As of March 31, 2008, CenterPoint Houston had no borrowings
and approximately $4 million of outstanding letters of credit under its $300 million credit
facility and CERC Corp. had $100 million of borrowings and $35 million of commercial paper
outstanding under its $950 million credit facility. The Company, CenterPoint Houston and CERC
Corp. were in compliance with all debt covenants as of March 31, 2008.

Transition Bonds.
Pursuant to a financing order issued by the Texas Utility Commission in
September 2007, in February 2008 a subsidiary of CenterPoint Houston issued approximately $488
million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final
maturity dates of February 2020 and February 2023, respectively. Scheduled final payment dates are
February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston
securitized transition property of approximately $483 million representing the remaining balance of
the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount
of the fuel reconciliation settlement. See Note 4(a) for further discussion.

Convertible Debt.
On May 19, 2003, the Company issued $575 million aggregate principal amount
of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. As of March 31, 2008,
holders could convert each of their notes into shares of CenterPoint Energy common stock at a
conversion rate of 89.4381 shares of common stock per $1,000 principal amount of notes at any time
prior to maturity under the following circumstances: (1) if the last reported sale price of
CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive
trading days ending on the last trading day of the previous calendar quarter is greater than or
equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint
Energy common stock on such last trading day, (2) if the notes have been called for redemption,
(3) during any period in which the credit ratings assigned to the notes by both Moodys Investors
Service, Inc. (Moodys) and Standard & Poors Ratings Services (S&P), a division of The McGraw-Hill
Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least
one of these ratings services or their successors, or (4) upon the occurrence of specified
corporate transactions, including the distribution to all holders of CenterPoint Energy common
stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at
less than the last reported sale price of a share of CenterPoint Energy common stock on the trading
day prior to the declaration date of the distribution or the distribution to all holders of
CenterPoint Energy common stock of the Companys assets, debt securities or certain rights to
purchase the Companys securities, which distribution has a per share value exceeding 15% of the
last reported sale price of a share of CenterPoint Energy common stock on the trading day
immediately preceding the declaration date for such distribution. The notes originally had a
conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes. However,
the conversion rate increased to 89.4381 shares at March 31, 2008, in accordance with the terms of
the notes, because quarterly common stock dividends declared were in excess of $0.10 per share.

Holders have the right to require the Company to purchase all or any portion of the notes for
cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the
principal amount of the notes. The convertible senior notes also have a contingent interest feature
requiring contingent interest to be paid to holders of

notes commencing on or after May 15, 2008, in the event that the average trading price of a
note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of
the note as of the day immediately preceding the first day of the applicable six-month interest
period. For any six-month period, contingent interest will be equal to 0.25% of the average trading
price of the note for the applicable five-trading-day period.

In August 2005, the Company accepted for exchange approximately $572 million aggregate
principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of
its new 3.75% convertible senior notes due 2023 (New Notes). As of March 31, 2008, New Notes of
approximately $401 million remained outstanding and Old Notes of approximately $1 million remained
outstanding. Under the terms of the New Notes, which are substantially similar to the Old Notes,
settlement of the principal portion will be made in cash rather than stock.

During the three months ended March 31, 2008, the Company issued 4.4 million shares of its
common stock and paid cash of approximately $131 million to settle conversions of approximately
$133 million principal amount of its 3.75% convertible senior notes. In April 2008, the Company
issued 0.25 million shares of its common stock and paid cash of approximately $11 million to settle
a conversion of approximately $11 million principal amount of its convertible notes.

As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior notes are included as
current portion of long-term debt in the Consolidated Balance Sheets because the last reported sale
price of CenterPoint Energy common stock for at least 20 trading days during the period of 30
consecutive trading days ending on the last trading day of the quarter was greater than or equal to
120% of the conversion price of the 3.75% convertible senior notes and therefore, the 3.75%
convertible senior notes meet the criteria that make them eligible for conversion at the option of
the holders of these notes.

In April 2008, the Company announced a call for redemption of its 3.75% convertible senior
notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are
expected to be converted by holders prior to the redemption date, and substantially all of such
conversions are expected to be settled with a cash payment for the principal amount and delivery of
shares of the Companys common stock for the excess value due converting holders. If the Companys
closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions,
assuming the conversion of approximately $391 million aggregate principal amount of the notes at
the current conversion rate, common stock reflecting a conversion
premium of $153 million would be issued
to the converting holders. The conversion rate will be increased as a result of the Companys
April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share. Under the
terms of the indenture governing the notes, the increased conversion rate will be
determined on May 13, 2008.

Purchase of Pollution Control Bonds.
In April 2008, the Company purchased $175 million
principal amount of pollution control bonds issued on its behalf at 102% of their principal amount.
Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of
7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending
on market conditions, the Company expects to remarket both series of bonds, at 100% of their
principal amounts, in 2008.

(10) Commitments and Contingencies

(a) Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to the Companys Natural
Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have
various quantity requirements and durations, that are not classified as non-trading derivative
assets and liabilities in the Companys Consolidated Balance Sheets as of December 31, 2007 and
March 31, 2008 as these contracts meet the SFAS No. 133 exception to be classified as normal
purchases contracts or do not meet the definition of a derivative. Natural gas supply commitments
also include natural gas transportation contracts which do not meet the definition of a derivative.
As of March 31, 2008, minimum payment obligations for natural gas supply commitments are
approximately $532 million for the remaining nine months in 2008, $316 million in 2009, $296
million in 2010, $279 million in 2011, $272 million in 2012 and $1.2 billion after 2012.

The Company, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant
Energy), and certain of their former subsidiaries are named as defendants in several lawsuits
described below. Under a master separation agreement between the Company and Reliant Energy, Inc.
(formerly Reliant Resources, Inc.) (RRI), the Company and its subsidiaries are entitled to be
indemnified by RRI for any losses, including attorneys fees and other costs, arising out of the
lawsuits described below under Electricity and Gas Market Manipulation Cases and Other Class
Action Lawsuits. Pursuant to the indemnification obligation, RRI is defending the Company and its
subsidiaries to the extent named in these lawsuits. Although the ultimate outcome of these matters
cannot be predicted at this time, the Company has not considered it necessary to establish reserves
related to this litigation.

Electricity and Gas Market Manipulation Cases.
A large number of lawsuits have been filed
against numerous market participants and remain pending in federal court in Nevada and in state
court in California, Missouri and Nevada in connection with the operation of the electricity and
natural gas markets in California and certain other states in 2000-2001, a time of power shortages
and significant increases in prices. These lawsuits, many of which have been filed as class
actions, are based on a number of legal theories, including violation of state and federal
antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer
Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of
contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include
state officials and governmental entities as well as private litigants, are seeking a variety of
forms of relief, including recovery of compensatory damages (in some cases in excess of $1
billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution,
interest due, disgorgement, civil penalties and fines, costs of suit and attorneys fees. The
Companys former subsidiary, RRI, was a participant in the California markets, owning generating
plants in the state and participating in both electricity and natural gas trading in that state and
in western power markets generally.

The Company and/or Reliant Energy have been named in approximately 35 of these lawsuits, which
were instituted between 2001 and 2007 and are pending in Nevada state court in Clark County, in
Missouri state court in Jackson County and in federal district court in Nevada. However, the
Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural
gas markets in California. The Company and Reliant Energy have been dismissed from certain of the
lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes
it is not a proper defendant in the remaining cases and will continue to seek dismissal from such
remaining cases.

To date, several of the electricity complaints have been dismissed, and several of the
dismissals have been affirmed by appellate courts. Others have been resolved by the settlement
described in the following paragraph. Three of the gas complaints were dismissed based on
defendants claims of the filed rate doctrine, but the Ninth Circuit Court of Appeals reversed
those dismissals and remanded the cases back to the district court for further proceedings. In June
2005, a San Diego state court refused to dismiss other gas complaints on the same basis. In October
2006, RRI reached a tentative settlement of 11 class action natural gas cases pending in state
court in California. The court approved this settlement in June 2007. In the remaining gas cases in
state court in California, the Court of Appeals found that the Company was not a successor to the
liabilities of a subsidiary of RRI and ordered the state court to dismiss the Company. The Company
was dismissed in April 2008. The other gas cases remain in the early procedural stages.

In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC)
enforcement staff, the states of California, Washington and Oregon, Californias three largest
investor-owned utilities, classes of consumers from California and other western states, and a
number of California city and county government entities that resolves their claims against RRI
related to the operation of the electricity markets in California and certain other western states
in 2000-2001. The settlement also resolves the claims of the three states and the investor-owned
utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the
FERC, by the California Public Utilities Commission and by the courts in which the electricity
class action cases are pending. Two parties have appealed the courts approval of the settlement to
the California Court of Appeals. A

party in the FERC proceedings filed a motion for rehearing of the FERCs order approving the
settlement, which the FERC denied in May 2006. That party has filed for review of the FERCs orders
in the Ninth Circuit Court of Appeals. The Company is not a party to the settlement, but may rely
on the settlement as a defense to any claims brought against it related to the time when the
Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company.

Other Class Action Lawsuits.
In May 2002, three class action lawsuits were filed in federal
district court in Houston on behalf of participants in various employee benefits plans sponsored by
the Company. Two of the lawsuits were dismissed without prejudice. In the remaining lawsuit, the
Company and certain former members of its benefits committee are defendants. That lawsuit alleged
that the defendants breached their fiduciary duties to various employee benefits plans, directly or
indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of
1974 by permitting the plans to purchase or hold securities issued by the Company when it was
imprudent to do so, including after the prices for such securities became artificially inflated
because of alleged securities fraud engaged in by the defendants. The complaint sought monetary
damages for losses suffered on behalf of the plans and a putative class of plan participants whose
accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the
federal district judge granted a motion for summary judgment filed by the Company and the
individual defendants. The plaintiffs appealed the ruling to the
Fifth Circuit Court of Appeals (Fifth Circuit), which in April 2008 affirmed the district courts ruling. The plaintiffs could
seek rehearing of that decision by Fifth Circuit and, if that is unsuccessful, further review by
the United States Supreme Court.
The Company
believes that this lawsuit is without merit and will continue to vigorously defend the case.
However, the ultimate outcome of this matter cannot be predicted at this time.

Other Legal Matters

Natural Gas Measurement Lawsuits.
CERC Corp. and certain of its subsidiaries are defendants in
a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas
produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs and fees. The complaint is part of a larger series of complaints filed
against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action
making substantially similar allegations against the pipelines was dismissed by the federal
district court for the District of Columbia on grounds of improper joinder and lack of
jurisdiction. As a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other similar False
Claims Act cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the judge
considering this matter granted the defendants motion to dismiss the suit on the ground that the
court lacked subject matter jurisdiction over the claims asserted. The plaintiff has sought review
of that dismissal from the Tenth Circuit Court of Appeals, where the matter remains pending.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement
lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state
court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four
times), the plaintiffs purport to represent a class of royalty owners who allege that the
defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25
years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from
the judge denying certification of the plaintiffs alleged class. In the amendment the plaintiffs
dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited
the scope of the class of plaintiffs they purport to represent and eliminated previously asserted
claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty
owners, in which they assert their claims that the defendants have engaged in systematic
mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the
plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. CERC believes that there has been no systematic mismeasurement of gas and that the
lawsuits are without merit. CERC does not expect the ultimate outcome of the lawsuits to have a
material impact on the financial condition, results of operations or cash flows of either the
Company or CERC.

Gas Cost Recovery Litigation.
In October 2002, a lawsuit was filed on behalf of certain CERC
ratepayers in state district court in Wharton County, Texas against the Company, CERC, Entex Gas
Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the
Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and
violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain
consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a
class of Texas ratepayers, but subsequently dropped their request for class certification. The

plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy
Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC, and other non-affiliated
companies. In February 2005, the case was removed to federal district court in Houston, Texas, and
in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims
asserted unless the Miller County case described below is not certified as a class action or is
later decertified.

In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in
circuit court in Miller County, Arkansas against the Company, CERC, EGMC, CenterPoint Energy Gas
Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River
Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and
civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas,
Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT
and MRT as defendants. Although the plaintiffs in the Miller County case sought class
certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the
Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service
Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but
refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the
Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court
subsequently dismissed the case in accordance with the Arkansas Supreme Courts mandate and all
appellate deadlines have expired.

In June 2007, the Company, CERC, EGMC and other defendants in the Miller County case filed a
petition in a district court in Travis County, Texas seeking a determination that the Railroad
Commission has original exclusive jurisdiction over the Texas claims asserted in the Miller County
case. In October 2007, CEFS and CEPS were joined as plaintiffs to the Travis County case.

In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint
at the APSC seeking a decision concerning the extent of the APSCs jurisdiction over the Miller
County case and an investigation into the merits of the allegations asserted in his complaint with
respect to CERC. That complaint remains pending at the APSC.

In February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana against CERC
with respect to rates charged to a purported class of certain consumers of natural gas and gas
service in the State of Louisiana. In February 2004, another suit was filed in state court in
Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas
services allegedly provided by CERC to a purported class of certain consumers of natural gas and
gas service without advance approval by the Louisiana Public Service Commission (LPSC). At the time
of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed
petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu
Parish lawsuits have been stayed pending the resolution of the petitions filed with the LPSC. In
August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by
the plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, CERCs gas purchases
were reviewed back to 1971. The review concluded that CERCs gas costs were reasonable and
prudent, but CERC agreed to credit to jurisdictional customers approximately $920,000, including
interest, related to certain off-system sales. A regulatory liability was established and the
Company began refunding that amount to jurisdictional customers in September 2007. A similar review
by the LPSC related to the Caddo Parish litigation was resolved without additional payment by CERC.

The range of relief sought by the plaintiffs in these cases includes injunctive and
declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of
actual damages, civil penalties and attorneys fees. The Company, CERC and their affiliates deny
that they have overcharged any of their customers for natural gas and believe that the amounts
recovered for purchased gas have been shown in the reviews described above to be in accordance with
what is permitted by state and municipal regulatory authorities. The Company and CERC do not expect
the outcome of these matters to have a material impact on the financial condition, results of
operations or cash flows of either the Company or CERC.

Storage Facility Litigation.
In February 2007, an Oklahoma district court in Coal County,
Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint
Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands
underlying CEGTs Chiles Dome Storage Facility. The dispute concerns native gas that may have
been in the Wapanucka formation underlying the Chiles Dome facility when that facility was
constructed in 1979 by a CERC entity that was the predecessor in interest of CEGT.

The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT
nor its predecessors had condemned those ownership interests. The court rejected CEGTs contention
that the claim should be barred by the statute of limitations, since the suit was filed over 25
years after the facility was constructed. The court also rejected CEGTs contention that the suit
is an impermissible attack on the determinations the FERC and Oklahoma Corporation Commission made
regarding the absence of native gas in the lands when the facility was constructed. The summary
judgment ruling was only on the issue of liability, though the court did rule that CEGT has the
burden of proving that any gas in the Wapanucka formation is gas that has been injected and is not
native gas. Further hearings and orders of the court are required to specify the appropriate relief
for the plaintiffs. CEGT plans to appeal through the Oklahoma court system any judgment that
imposes liability on CEGT in this matter. The Company and CERC do not expect the outcome of this
matter to have a material impact on the financial condition, results of operations or cash flows of
either the Company or CERC.

Environmental Matters

Manufactured Gas Plant Sites.
CERC and its predecessors operated manufactured gas plants (MGP)
in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing
monitoring and water treatment. There are five remaining sites in CERCs Minnesota service
territory. CERC believes that it has no liability with respect to two of these sites.

At March 31, 2008, CERC had accrued $14 million for remediation of these Minnesota sites and
the estimated range of possible remediation costs for these sites was $4 million to $35 million
based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a
site or industry average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites to be remediated, the participation of other
potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized
an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in
excess of insurance recovery. As of March 31, 2008, CERC had collected $13 million from insurance
companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and
other regulators have investigated MGP sites that were owned or operated by CERC or may have been
owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the
United States District Court, District of Maine, under which contribution is sought by private
parties for the cost to remediate former MGP sites based on the previous ownership of such sites by
former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of
Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in
Maine ruled that the current owner of the site is responsible for site remediation but that an
additional evidentiary hearing is required to determine if other potentially responsible parties,
including CERC, would have to contribute to that remediation. The Company is investigating details
regarding the site and the range of environmental expenditures for potential remediation. However,
CERC believes it is not liable as a former owner or operator of the site under the Comprehensive
Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state
statutes, and is vigorously contesting the suit and its designation as a PRP.

Mercury Contamination.
The Companys pipeline and distribution operations have in the past
employed elemental mercury in measuring and regulating equipment. It is possible that small amounts
of mercury may have been spilled in the course of normal maintenance and replacement operations and
that these spills may have contaminated the immediate area with elemental mercury. The Company has
found this type of contamination at some sites in the past, and the Company has conducted
remediation at these sites. It is possible that other contaminated sites may exist and that
remediation costs may be incurred for these sites. Although the total amount of these costs is not
known at this time, based on the Companys experience and that of others in the natural gas
industry to date and on the current regulations regarding remediation of these sites, the Company
believes that the costs of any remediation of these sites will not be material to the Companys
financial condition, results of operations or cash flows.

Asbestos.
Some facilities owned by the Company contain or have contained asbestos insulation
and other asbestos-containing materials. The Company or its subsidiaries have been named, along
with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury
due to exposure to asbestos. Some of the claimants have worked at locations owned by the Company,
but most existing claims relate to facilities previously owned by the Company or its subsidiaries.
The Company anticipates that additional claims like those received may

be asserted in the future. In 2004, the Company sold its generating business, to which most of
these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP (NRG). Under the terms
of the arrangements regarding separation of the generating business from the Company and its sale
to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to
the generating business has been assumed by Texas Genco LLC and its successor, but the Company has
agreed to continue to defend such claims to the extent they are covered by insurance maintained by
the Company, subject to reimbursement of the costs of such defense from the purchaser. Although
their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously
contesting claims that it does not consider to have merit and does not expect, based on its
experience to date, these matters, either individually or in the aggregate, to have a material
adverse effect on the Companys financial condition, results of operations or cash flows.

Other Environmental.
From time to time the Company has received notices from regulatory
authorities or others regarding its status as a PRP in connection with sites found to require
remediation due to the presence of environmental contaminants. In addition, the Company has been
named from time to time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters cannot be predicted at this time, the Company does not expect, based on its
experience to date, these matters, either individually or in the aggregate, to have a material
adverse effect on the Companys financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies regarding matters arising in the
ordinary course of business. Some of these proceedings involve substantial amounts. The Company
regularly analyzes current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. The Company does not expect the
disposition of these matters to have a material adverse effect on the Companys financial
condition, results of operations or cash flows.

Guaranties

Prior to the Companys distribution of its ownership in RRI to its shareholders, CERC had
guaranteed certain contractual obligations of what became RRIs trading subsidiary. Under the terms
of the separation agreement between the companies, RRI agreed to extinguish all such guaranty
obligations prior to separation, but at the time of separation in September 2002, RRI had been
unable to extinguish all obligations. To secure CERC against obligations under the remaining
guaranties, RRI agreed to provide cash or letters of credit for CERCs benefit, and undertook to
use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the
Company, CERC and RRI amended that agreement and CERC released the letters of credit it held as
security. Under the revised agreement RRI agreed to provide cash or new letters of credit to
secure CERC against exposure under the remaining guaranties as calculated under the new agreement
if and to the extent changes in market conditions exposed CERC to a risk of loss on those
guaranties.

The potential exposure of CERC under the guaranties relates to payment of demand charges
related to transportation contracts. RRI continues to meet its obligations under the contracts,
and, on the basis of current market conditions, the Company and CERC believe that additional
security is not needed at this time. However, if RRI should fail to perform its obligations under
the contracts or if RRI should fail to provide adequate security in the event market conditions
change adversely, the Company would retain exposure to the counterparty under the guaranty.

(11) Income Taxes

During the three months ended March 31, 2007 and 2008, the effective tax rate was 36% and 37%,
respectively. The most significant item affecting the comparability of the effective tax rate is
the 2008 classification of approximately $4 million of Texas margin tax as an income tax for
CenterPoint Houston.

The following table summarizes the Companys liability for uncertain tax positions in
accordance with FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes  an
Interpretation of FASB Statement No. 109, at December 31, 2007 and March 31, 2008 (in millions):

December 31,

March 31,

2007

2008

Liability for uncertain tax positions

$

82

$

89

Portion of liability for uncertain tax
positions that, if recognized, would
reduce the effective income tax rate

10

11

Interest accrued on uncertain tax positions

4

5

(12) Earnings Per Share

The following table reconciles numerators and denominators of the Companys basic and diluted
earnings per share calculations:

Three Months Ended March 31,

2007

2008

(in millions, except share and

per share amounts)

Basic earnings per share calculation:

Net income

$

130

$

123

Weighted average shares outstanding

318,060,000

327,279,000

Basic earnings per share:

Net income

$

0.41

$

0.38

Diluted earnings per share calculation:

Net income

$

130

$

123

Weighted average shares outstanding

318,060,000

327,279,000

Plus: Incremental shares from assumed conversions:

Stock options (1)

1,237,000

869,000

Restricted stock

1,328,000

1,127,000

2.875% convertible senior notes

1,179,000



3.75% convertible senior notes

18,299,000

10,173,000

Weighted average shares assuming dilution

340,103,000

339,448,000

Diluted earnings per share:

Net income

$

0.38

$

0.36

(1)

Options to purchase 3,752,647 and 2,848,340 shares were outstanding for the three months
ended March 31, 2007 and 2008, respectively, but were not included in the computation of
diluted earnings per share because the options exercise price was greater than the average
market price of the common shares for the respective periods.

Substantially all of the 3.75% contingently convertible senior notes provide for settlement of
the principal portion in cash rather than stock. In accordance with EITF Issue No. 04-8,
Accounting Issues related to Certain Features of Contingently Convertible Debt and the Effect on
Diluted Earnings Per Share, the portion of the conversion value of such notes that must be settled
in cash rather than stock is excluded from the computation of diluted earnings per share from
continuing operations. The Company includes the conversion spread in the calculation of diluted
earnings per share when the average market price of the Companys common stock in the respective
reporting period exceeds the conversion price. The conversion price for the 3.75% contingently
convertible senior notes at March 31, 2008 was $11.18.

(13) Reportable Business Segments

The Companys determination of reportable business segments considers the strategic operating
units under which the Company manages sales, allocates resources and assesses performance of
various products and services to

wholesale or retail customers in differing regulatory environments. The accounting policies of
the business segments are the same as those described in the summary of significant accounting
policies except that some executive benefit costs have not been allocated to business segments. The
Company uses operating income as the measure of profit or loss for its business segments.

The Companys reportable business segments include the following: Electric Transmission &
Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate
Pipelines, Field Services and Other Operations. The electric transmission and distribution function
(CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment.
Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas
transportation and distribution for, residential, commercial, industrial and institutional
customers. Competitive Natural Gas Sales and Services represents the Companys non-rate regulated
gas sales and services operations, which consist of three operational functions: wholesale, retail
and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural
gas pipeline operations. The Field Services business segment includes the natural gas gathering
operations. Other Operations consists primarily of other corporate operations which support all of
the Companys business operations.

Long-lived assets include net property, plant and equipment, net goodwill and other
intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are
eliminated in consolidation.

Financial data for business segments and products and services are as follows (in millions):

For the Three Months Ended March 31, 2007

Revenues from

Net

Total Assets

External

Intersegment

Operating

as of December 31,

Customers

Revenues

Income (Loss)

2007

Electric Transmission & Distribution

$

406

(1)

$



$

104

$

8,358

Natural Gas Distribution

1,564

3

129

4,332

Competitive Natural Gas Sales and Services

1,047

17

56

1,221

Interstate Pipelines

59

31

44

3,007

Field Services

28

11

22

669

Other Operations

2



(2

)

1,956

(2)

Eliminations



(62

)



(1,671

)

Consolidated

$

3,106

$



$

353

$

17,872

For the Three Months Ended March 31, 2008

Revenues from

Net

Total Assets

External

Intersegment

Operating

as of March 31,

Customers

Revenues

Income (Loss)

2008

Electric Transmission & Distribution

$

409

(1)

$



$

91

$

8,221

Natural Gas Distribution

1,697

3

121

4,171

Competitive Natural Gas Sales and Services

1,109

11

6

1,316

Interstate Pipelines

91

42

71

3,087

Field Services

54

4

45

724

Other Operations

3



2

2,050

(2)

Eliminations



(60

)



(2,034

)

Consolidated

$

3,363

$



$

336

$

17,535

(1)

Sales to subsidiaries of RRI in the three months ended March 31, 2007 and 2008 represented
approximately $149 million and $142 million, respectively, of CenterPoint Houstons
transmission and distribution revenues.

(2)

Included in total assets of Other Operations as of December 31, 2007 and March 31, 2008 are
pension assets of $231 million and $236 million, respectively. Also included in total assets
of Other Operations as of December 31, 2007 and March 31, 2008, are pension related regulatory
assets of $319 million and $317 million, respectively, resulting from the Companys adoption
of SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement
Plans  An Amendment of FASB Statements No. 87, 88, 106 and 132(R).

On April 24, 2008, the Companys board of directors declared a regular quarterly cash dividend
of $0.1825 per share of common stock payable on June 10, 2008, to shareholders of record as of the
close of business on May 16, 2008.

Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed
Financial Statements contained in this
Form 10-Q
and our Annual Report on
Form 10-K
for the year
ended December 31, 2007 (2007
Form 10-K
).

EXECUTIVE SUMMARY

Recent Events

Debt Financing Transactions

In April 2008, we purchased $175 million principal amount of pollution control bonds issued on
our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount
of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds
had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both
series of bonds, at 100% of their principal amounts, in 2008.

During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock
and paid cash of approximately $131 million to settle conversions of approximately $133 million
principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402
million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of
our common stock and paid cash of approximately $11 million to settle a conversion of approximately
$11 million principal amount of our 3.75% convertible notes.

In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at
100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to
be converted by holders prior to the redemption date, and substantially all of such conversions are
expected to be settled with a cash payment for the principal amount and delivery of shares of our
common stock for the excess value due converting holders. If our
closing stock price of $15.57 at
April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of
approximately $391 million aggregate principal amount of the notes at the current conversion rate,
common stock reflecting a conversion premium of $153 million would be issued to the converting holders.
The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular
quarterly cash dividend of $0.1825 per share. Under the terms of the indenture governing the
notes, the increased conversion rate will be determined on May 13, 2008.

Transition Bonds

Pursuant to a financing order issued by the Public Utility Commission of Texas (Texas Utility
Commission) in September 2007, in February 2008 a subsidiary of CenterPoint Energy Houston
Electric, LLC (CenterPoint Houston) issued approximately $488 million in transition bonds in two
tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and
February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020.
Through issuance of the transition bonds, CenterPoint Houston securitized transition property of
approximately $483 million representing the remaining balance of the competition transition charge
(CTC) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of
the fuel reconciliation settlement.

Interstate Pipelines

In May 2007, CenterPoint Energy Gas Transmission (CEGT), a wholly owned subsidiary of CERC
Corp., received Federal Energy Regulatory Commission (FERC) approval for the third phase of its
Carthage to Perryville pipeline project, a 172-mile, 42-inch diameter pipeline and related
compression facilities for the transportation of gas from Carthage, Texas to CEGTs Perryville hub
in northeast Louisiana, to expand capacity of the pipeline to 1.5 Bcf per day by adding additional
compression and operating at higher pressures. In July 2007, CEGT received approval from the
Pipeline and Hazardous Materials Administration (PHMSA) to increase the maximum allowable operating
pressure. The PHMSAs approval contained certain conditions and requirements. In March 2008, CEGT
met these conditions and gave notice to PHMSA that it would be increasing the pressure in 30 days.
In April 2008, CEGT raised the maximum allowable pressure and concurrently placed the phase three
expansion in-service. CEGT has executed contracts for approximately 150 MMcf per day of the 250
MMcf per day phase three expansion.

In September 2007, CEGT initiated an investigation into allegations received from two former
employees of the manufacturer of pipe installed in CEGTs Carthage to Perryville pipeline segment.
That pipeline segment was placed in commercial service in May 2007 after satisfactory completion of
hydrostatic testing designed to ensure that the pipe and its welds would be structurally sound when
placed in service and operated at design pressure. According to the complainants, records relating
to radiographic inspections of certain welds made at the fabrication facility had been altered
resulting in the possibility that pipe with alleged substandard welds had been installed in the
pipeline. In conducting its investigation, among other things, CEGT and its counsel interviewed the
complainants and other individuals, including CEGT and contractor personnel, and reviewed
documentation related to the manufacture and construction of the pipeline, including radiographic
records related to the allegedly deficient welds. CEGT kept appropriate governmental officials
informed throughout its investigation and consulted appropriate technical consultants and
pre-existing regulatory guidance. Pursuant to a course of action proposed by CEGT,
CEGT
excavated and inspected certain welds, and in each case, CEGT found those welds to be structurally
sound. CEGT and its counsel have now formally concluded their investigation, finding
no credible support for the allegation that pipe with substandard welds may have been installed
in the pipeline. CEGT has informed the relevant government agencies of these conclusions, and has
informed those agencies that CEGT does not intend to take any additional action or to alter or
modify the pipelines operations.

Effective April 1, 2008, Mississippi River Transmission Corp. signed a 5-year extension of its
firm transportation and storage contracts with Laclede Gas Company (Laclede). In 2007,
approximately 10% of Interstate Pipelines operating revenues was attributable to services provided
to Laclede.

CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.

Three Months Ended March 31,

2007

2008

Revenues

$

3,106

$

3,363

Expenses

2,753

3,027

Operating Income

353

336

Interest and Other Finance Charges

(123

)

(115

)

Interest on Transition Bonds

(31

)

(33

)

Other Income, net

3

9

Income Before Income Taxes

202

197

Income Tax Expense

(72

)

(74

)

Net Income

$

130

$

123

Basic Earnings Per Share

$

0.41

$

0.38

Diluted Earnings Per Share

$

0.38

$

0.36

Three months ended March 31, 2008 compared to three months ended March 31, 2007

We reported consolidated net income of $123 million ($0.36 per diluted share) for the three
months ended March 31, 2008 as compared to $130 million ($0.38 per diluted share) for the same
period in 2007. The decrease in net income of $7 million was primarily due to decreased operating
income of $50 million in our Competitive Natural Gas Sales and Services business segment, decreased
operating income of $14 million in our Electric Transmission & Distribution utility and decreased
operating income of $8 million in our Natural Gas Distribution business segment. These decreases
in consolidated net income were partially offset by increased operating income of $27 million in
our Interstate Pipelines business segment, increased operating income of $23 million in our Field
Services business segment, decreased interest expense, excluding interest on transition bonds, of
$8 million due to lower amortization of deferred financing costs and increased operating income of
$4 million in our Other Operations business segment.

During the three months ended March 31, 2008 and 2007, the effective tax rate was 37% and 36%,
respectively. The most significant item affecting the comparability of the effective tax rate is
the 2008 classification of approximately $4 million of Texas margin tax as an income tax for
CenterPoint Houston.

The following table presents operating income (in millions) for each of our business segments
for the three months ended March 31, 2007 and 2008.

Three Months Ended March 31,

2007

2008

Electric Transmission & Distribution

$

104

$

91

Natural Gas Distribution

129

121

Competitive Natural Gas Sales and Services

56

6

Interstate Pipelines

44

71

Field Services

22

45

Other Operations

(2

)

2

Total Consolidated Operating Income

$

353

$

336

Electric Transmission & Distribution

For information regarding factors that may affect the future results of operations of our
Electric Transmission & Distribution business segment, please read Risk Factors  Risk Factors
Affecting Our Electric Transmission & Distribution Business,   Risk Factors Associated with Our
Consolidated Financial Condition and  Risks Common to Our Business and Other Risks in Item 1A
of Part I of our 2007 Form 10-K.

The following tables provide summary data of our Electric Transmission & Distribution business
segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and
customer data):

Three Months Ended March 31,

2007

2008

Revenues:

Electric transmission and distribution utility

$

347

$

346

Transition bond companies

59

63

Total revenues

406

409

Expenses:

Operation and maintenance, excluding transition bond companies

154

168

Depreciation
and amortization, excluding transition bond companies

63

66

Taxes other than income taxes

57

53

Transition bond companies

28

31

Total expenses

302

318

Operating Income

$

104

$

91

Operating Income:

Electric transmission and distribution utility

62

54

Competition transition charge

11

5

Transition bond companies (1)

31

32

Total segment operating income

$

104

$

91

Throughput (in gigawatt-hours (GWh)):

Residential

4,658

4,403

Total

16,660

16,570

Average number of metered customers:

Residential

1,752,264

1,801,272

Total

1,989,744

2,042,460

(1)

Represents the amount necessary to pay interest on the transition bonds.

Three months ended March 31, 2008 compared to three months ended March 31, 2007

Our Electric Transmission & Distribution business segment reported operating income of $91
million for the three months ended March 31, 2008, consisting of $54 million for the regulated
electric transmission and distribution utility (TDU), $5 million for the CTC and $32 million
related to the transition bonds. For the three months ended March 31, 2007, operating income
totaled $104 million, consisting of $62 million for the TDU, $11 million for the CTC and $31
million related to the transition bonds. The reduction in operating income from the TDU resulted
from reduced usage ($11 million), in part due to milder weather, higher operating expenses ($8
million), and higher net transmission costs ($3 million), partially offset by higher revenues ($7
million) due to customer growth from the addition of over 52,000 new customers and higher revenues
from ancillary services ($2 million). Taxes other than income taxes were lower by $4 million
primarily as a result of the Texas margin tax being classified as an income tax for reporting
purposes in 2008.

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our
Natural Gas Distribution business segment, please read Risk Factors  Risk Factors Affecting Our
Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and
Field Services Businesses,   Risk Factors Associated with Our Consolidated Financial Condition
and  Risks Common to Our Business and Other Risks in Item 1A of Part I of our 2007 Form 10-K.

The following table provides summary data of our Natural Gas Distribution business segment for
the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):

Three Months Ended March 31,

2007

2008

Revenues

$

1,567

$

1,700

Expenses:

Natural gas

1,212

1,333

Operation and maintenance

147

156

Depreciation and amortization

38

39

Taxes other than income taxes

41

51

Total expenses

1,438

1,579

Operating Income

$

129

$

121

Throughput (in Bcf):

Residential

86

84

Commercial and industrial

81

83

Total Throughput

167

167

Average number of customers:

Residential

2,946,203

2,975,591

Commercial and industrial

245,576

250,988

Total

3,191,779

3,226,579

Three months ended March 31, 2008 compared to three months ended March 31, 2007

Our Natural Gas Distribution business segment reported operating income of $121 million for
the three months ended March 31, 2008 compared to operating income of $129 million for the three
months ended March 31, 2007. Operating margin (revenues less cost of gas) increased $12 million
primarily due to increases in gross receipts taxes ($9 million) and recovery of energy-efficiency
costs ($3 million), both of which are offset by the related expenses. Other margin increases
primarily from new rates ($5 million) and customer growth ($3 million), with the addition of nearly
36,000 customers, was entirely offset by the cost of a winter weather hedge and customer
conservation ($11 million). Operation and maintenance expenses increased primarily due to the
energy efficiency costs above and higher bad debt expense ($2 million) related to higher revenues.

For information regarding factors that may affect the future results of operations of our
Competitive Natural Gas Sales and Services business segment, please read Risk Factors  Risk
Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services,
Interstate Pipelines and Field Services Business,   Risk Factors Associated with Our
Consolidated Financial Condition and  Risks Common to Our Business and Other Risks in Item 1A
of Part I of our 2007 Form 10-K.

The following table provides summary data of our Competitive Natural Gas Sales and Services
business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput
and customer data):

Three Months Ended March 31,

2007

2008

Revenues

$

1,064

$

1,120

Expenses:

Natural gas

998

1,105

Operation and maintenance

9

8

Depreciation and amortization



1

Taxes other than income taxes

1



Total expenses

1,008

1,114

Operating Income

$

56

$

6

Throughput (in Bcf):

Wholesale  third parties

94

70

Wholesale  affiliates

3

2

Retail and Pipeline

58

66

Total Throughput

155

138

Average number of customers:

Wholesale

223

154

Retail and Pipeline

6,764

8,338

Total

6,987

8,492

Three months ended March 31, 2008 compared to three months ended March 31, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of
$6 million for the three months ended March 31, 2008 compared to $56 million for the three months
ended March 31, 2007. The decrease in operating income of $50 million was primarily due to higher
operating margins (revenues less natural gas costs) in 2007 related to sales of gas from inventory
that was written down to the lower of cost or market in prior periods
of $28 million in the first
quarter of 2007 compared to $4 million in the first quarter of 2008 for a net decrease of $24
million. Our Competitive Natural Gas Sales and Services business segment purchases and stores
natural gas to meet certain future sales requirements and enters into derivative contracts to hedge
the economic value of the future sales. The unfavorable mark-to-market accounting for non-trading
financial derivatives for the first quarter of 2008 of $22 million versus $8 million for the same
period in 2007 accounted for a further net $14 million decrease. The additional decrease in
operating income of $12 million in this quarter compared to the same quarter last year was
primarily due to a reduction in margin as basis and summer/winter spreads narrowed.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our
Interstate Pipelines business segment, please read Risk Factors  Risk Factors Affecting Our
Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and
Field Services Businesses,   Risk Factors Associated with Our Consolidated Financial Condition
and  Risks Common to Our Business and Other Risks in Item 1A of Part I of our 2007 Form 10-K.

The following table provides summary data of our Interstate Pipelines business segment for the
three months ended March 31, 2007 and 2008 (in millions, except throughput data):

Three Months Ended March 31,

2007

2008

Revenues

$

90

$

133

Expenses:

Natural gas

4

15

Operation and maintenance

27

30

Depreciation and amortization

10

12

Taxes other than income taxes

5

5

Total expenses

46

62

Operating Income

$

44

$

71

Throughput (in Bcf ):

Transportation

294

424

Three months ended March 31, 2008 compared to three months ended March 31, 2007

The Interstate Pipeline business segment reported operating income of $71 million for the
three months ended March 31, 2008 compared to $44 million for the same period of 2007. The
increase in operating income of $27 million was primarily driven by the new Carthage to Perryville
pipeline ($19 million), other transportation and ancillary services ($8 million), and lower other
tax expense and refunds ($2 million). These favorable variances in operating income were partially
offset by a 2007 gain on sale of excess gas associated with storage enhancement projects ($2
million).

Field Services

For information regarding factors that may affect the future results of operations of our
Field Services business segment, please read Risk Factors  Risk Factors Affecting Our Natural Gas
Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services
Businesses,   Risk Factors Associated with Our Consolidated Financial Condition and  Risks
Common to Our Business and Other Risks in Item 1A of Part I of our 2007 Form 10-K.

The following table provides summary data of our Field Services business segment for the three
months ended March 31, 2007 and 2008 (in millions, except throughput data):

Three Months Ended March 31,

2007

2008

Revenues

$

39

$

58

Expenses:

Natural gas

(3

)

(2

)

Operation and maintenance

16

11

Depreciation and amortization

3

3

Taxes other than income taxes

1

1

Total expenses

17

13

Operating Income

$

22

$

45

Throughput (in Bcf ):

Gathering

93

98

Three months ended March 31, 2008 compared to three months ended March 31, 2007

The Field Services business segment reported operating income of $45 million for the three
months ended March 31, 2008 compared to $22 million for the same period of 2007. The increase in
operating income of $23 million was primarily driven by a one-time gain ($11 million) related to a
settlement and contract buyout of one of

our customers and a one-time gain ($6 million) related to the sale of assets, both recognized
in the first quarter of 2008. In addition to these one-time items, increased revenues from gas
gathering and ancillary services and higher commodity prices were partially offset by increased
operating expenses associated with new assets and general cost increases.

In addition, this business segment recorded equity income of $2 million and $4 million in the
three months ended March 31, 2007 and 2008, respectively, from its 50 percent interest in a
jointly-owned gas processing plant. These amounts are included in Other  net under the Other
Income (Expense) caption.

Other Operations

The following table shows the operating income (loss) of our Other Operations business segment
for the three months ended March 31, 2007 and 2008 (in millions):

Three Months Ended March 31,

2007

2008

Revenues

$

2

$

3

Expenses

4

1

Operating Income (Loss)

$

(2

)

$

2

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our
future earnings, please read Managements Discussion and Analysis of Financial Condition and
Results of Operations  Certain Factors Affecting Future Earnings in Item 7 of Part II and Risk
Factors in Item 1A of Part I of our 2007 Form 10-K, and Cautionary Statement Regarding
Forward-Looking Information.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and
financing activities for the three months ended March 31, 2007 and 2008:

Three Months Ended March 31,

2007

2008

(in millions)

Cash provided by (used in):

Operating activities

$

264

$

567

Investing activities

(403

)

(312

)

Financing activities

72

(314

)

Cash Provided by Operating Activities

Net cash provided by operating activities in the first quarter of 2008 increased $303 million
compared to the same period in 2007 primarily due to increased net accounts receivable/payable
($178 million) and decreased gas storage inventory ($116 million).

Cash Used in Investing Activities

Net cash used in investing activities decreased $91 million in the first quarter of 2008 as
compared to the same period in 2007 due to decreased capital expenditures of $212 million primarily
related to the completion of certain pipeline projects for our Interstate Pipelines business
segment, offset by increased investment in unconsolidated affiliates of $105 million primarily
related to the Southeast Supply Header (SESH) pipeline project, and increased restricted cash of
transition bond companies of $18 million.

Net cash used in financing activities in the first quarter of 2008 increased $386 million
compared to the same period in 2007 primarily due to decreased borrowings under revolving credit
facilities ($231 million), decreased short-term borrowings ($182 million) and increased repayments
of long-term debt ($81 million), which were partially offset by increased proceeds from the
issuance of long-term debt ($88 million) and increased proceeds from commercial paper ($35
million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations,
capital expenditures, debt service requirements, tax payments, working capital needs, various
regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements
for the remaining nine months of 2008 include the following:



approximately $813 million of capital expenditures;



cash settlement obligations in connection with possible conversions by holders of our
3.75% convertible senior notes, having an aggregate principal amount of $402 million at
March 31, 2008 or in connection with the redemption of such notes on May 30, 2008;



maturing long-term debt aggregating approximately $282 million, including $82 million
of transition bonds;



the cash purchase of $175 million of pollution control bonds issued on our behalf;



investment in and advances to SESH of approximately $185 million;



dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that borrowings under our credit facilities, the proceeds from the February 2008
issuance of $488 million of transition bonds (discussed below), anticipated cash proceeds from the
remarketing of $175 million of pollution control bonds purchased in April 2008 (discussed below)
and anticipated cash flows from operations will be sufficient to meet our cash needs in 2008. Cash
needs or discretionary financing or refinancing may also result in the issuance of equity or debt
securities in the capital markets.

Transition Bonds.
In February 2008, a new special purpose subsidiary of CenterPoint Houston
issued approximately $488 million in transition bonds pursuant to a financing order issued by the
Texas Utility Commission in September 2007. Through issuance of the transition bonds, CenterPoint
Houston securitized transition property of approximately $483 million representing the remaining
balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover
the amount of the fuel reconciliation settlement. Proceeds were used by the special purpose entity
to purchase $483 million of transition property from CenterPoint Houston and to pay costs of
issuance. Following a subsequent distribution to us, we used the proceeds for general corporate
purposes, including the repayment of debt and the making of loans to or investments in affiliates.

Purchase of Pollution Control Bonds.
In April 2008, we purchased $175 million principal
amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to
the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and
$75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market
conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in
2008.

Convertible Debt.
As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior
notes discussed in Note 9(b) to our consolidated financial statements have been included as current
portion of long-term debt in our Consolidated Balance Sheets because the last reported sale price
of our common stock for at least 20 trading days during the period of 30 consecutive trading days
ending on the last trading day of the fourth quarter of 2007 was greater than or equal to 120% of
the conversion price of the 3.75% convertible senior notes and therefore, during the

first quarter of 2008, the 3.75% convertible senior notes meet the criteria that make them
eligible for conversion at the option of the holders of these notes. During the three months ended
March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately
$131 million to settle conversions of approximately $133 million principal amount of our 3.75%
convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at
March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of
approximately $11 million to settle a conversion of approximately $11 million principal amount of
our 3.75% convertible notes.

In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at
100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to
be converted by holders prior to the redemption date, and substantially all of such conversions are
expected to be settled with a cash payment for the principal amount and delivery of shares of our
common stock for the excess value due converting holders. If our
closing stock price of $15.57 at
April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of
approximately $391 million aggregate principal amount of the notes at the current conversion rate,
common stock reflecting a conversion premium of $153 million would be issued to the converting holders.
The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular
quarterly cash dividend of $0.1825 per share. Under the terms of the indenture governing the
notes, the increased conversion rate will be determined on May 13, 2008.

Off-Balance Sheet Arrangements.
Other than operating leases and the guaranties described
below, we have no off-balance sheet arrangements.

Prior to the distribution of our ownership in Reliant Energy, Inc. (RRI) to our shareholders,
CERC had guaranteed certain contractual obligations of what became RRIs trading subsidiary. Under
the terms of the separation agreement between the companies, RRI agreed to extinguish all such
guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had
been unable to extinguish all obligations. To secure CERC against obligations under the remaining
guaranties, RRI agreed to provide cash or letters of credit for CERCs benefit, and undertook to
use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we,
CERC and RRI amended that agreement and CERC released the letters of credit it held as security.
Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC
against exposure under the remaining guaranties as calculated under the new agreement if and to the
extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

The potential exposure of CERC under the guaranties relates to payment of demand charges
related to transportation contracts. RRI continues to meet its obligations under the contracts,
and, on the basis of current market conditions, we and CERC believe that additional security is not
needed at this time. However, if RRI should fail to perform its obligations under the contracts or
if RRI should fail to provide adequate security in the event market conditions change adversely, we
would retain exposure to the counterparty under the guaranty.

Credit and Receivables Facilities.
As of March 31, 2008, we had the following facilities (in
millions):

Amount Utilized at

Date Executed

Company

Type of Facility

Size of Facility

March 31, 2008

Termination Date

June 29, 2007

CenterPoint Energy

Revolver

$

1,200

$

28

(1)

June 29, 2012

June 29, 2007

CenterPoint Houston

Revolver

300

4

(1)

June 29, 2012

June 29, 2007

CERC Corp.

Revolver

950

135

(2)

June 29, 2012

October 30, 2007

CERC

Receivables

375

200

October 28, 2008

(1)

Represents outstanding letters of credit.

(2)

Includes $100 million of borrowings under the credit facility and $35 million of
outstanding commercial paper supported by the CERC Corp. credit facility.

Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate
(LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt
(excluding transition bonds) to earnings before interest, taxes, depreciation and amortization
covenant.

CERC Corp.s $950 million credit facilitys first drawn cost is LIBOR plus 45 basis points
based on CERC Corp.s current credit ratings. The facility contains a debt to total capitalization
covenant.

Under each of the credit facilities, an additional utilization fee of 5 basis points applies
to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the
utilization fee fluctuate based on the borrowers credit rating. Borrowings under each of the
facilities are subject to customary terms and conditions. However, there is no requirement that we,
CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of
material adverse changes or litigation that could be expected to have a material adverse effect.
Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of
events of default that we, CenterPoint Houston or CERC Corp. consider customary.

We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business
and financial covenants contained in the respective receivables and credit facilities.

Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint Energy commercial paper
program under which we began issuing commercial paper in June 2005. The $950 million CERC Corp.
credit facility backstops a $950 million commercial paper program under which CERC Corp. began
issuing commercial paper in February 2008. As of March 31, 2008, there was no CenterPoint Energy
commercial paper outstanding and $35 million of CERC Corp. commercial paper outstanding. The
CenterPoint Energy commercial paper is rated Not Prime by Moodys Investors Service, Inc.
(Moodys), A-2 by Standard & Poors Rating Services (S&P), a division of The McGraw-Hill
Companies, and F3 by Fitch, Inc. (Fitch). The CERC Corp. commercial paper is rated P-3 by
Moodys, A-2 by S&P, and F2 by Fitch. As a result of the credit ratings on the two commercial
paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of
our short-term borrowing requirements. We cannot assure you that these ratings, or the credit
ratings set forth below in  Impact on Liquidity of a Downgrade in Credit Ratings, will remain in
effect for any given period of time or that one or more of these ratings will not be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to
buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency.
Each rating should be evaluated independently of any other rating. Any future reduction or
withdrawal of one or more of our credit ratings could have a material adverse impact on our ability
to obtain short- and long-term financing, the cost of such financings and the execution of our
commercial strategies.

Securities Registered with the SEC.
As of March 31, 2008, CenterPoint Energy had a shelf
registration statement covering senior debt securities, preferred stock and common stock
aggregating $750 million and CERC Corp. had a shelf registration statement covering $400 million
principal amount of senior debt securities.

Hedging of Future Debt Issuances.
As of March 31, 2008, we had outstanding treasury rate lock
derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million,
expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of
4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to
be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008.

Temporary Investments.
As of March 31, 2008, CERC Corp. had external temporary investments of
approximately $4 million.

Money Pool.
We have a money pool through which the holding company and participating
subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external
borrowing or investing is based on the net cash position. The net funding requirements of the money
pool are expected to be met with borrowings under our revolving credit facility or the sale of our
commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings.
As of April 15, 2008, Moodys, S&P, and
Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain
subsidiaries:

Moodys

S&P

Fitch

Company/Instrument

Rating

Outlook(1)

Rating

Outlook(2)

Rating

Outlook(3)

CenterPoint Energy Senior Unsecured
Debt

Ba1

Stable

BBB-

Stable

BBB-

Stable

CenterPoint Houston Senior Secured
Debt (First Mortgage Bonds)

Baa2

Stable

BBB+

Stable

A-

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

Stable

BBB

Stable

(1)

A stable outlook from Moodys indicates that Moodys does not expect to put the
rating on review for an upgrade or downgrade within 18 months from when the outlook was
assigned or last affirmed.

(2)

An S&P rating outlook assesses the potential direction of a long-term credit rating
over the intermediate to longer term.

(3)

A stable outlook from Fitch encompasses a one- to two-year horizon as to the likely
ratings direction.

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit
facility, CenterPoint Houstons $300 million credit facility and CERC Corp.s $950 million credit
facility. A decline in credit ratings would also increase the interest rate on long-term debt to be
issued in the capital markets and could negatively impact our ability to complete capital market
transactions. Additionally, a decline in credit ratings could increase cash collateral requirements
and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services
business segments.

In September 1999, we issued 2.0% ZENS having an original principal amount of $1.0 billion of
which $840 million remain outstanding. Each ZENS note is exchangeable at the holders option at any
time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner
Inc. common stock (TW Common) attributable to each ZENS note. If our creditworthiness were to drop
such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS
notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for
cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of
TW Common that we own or from other sources. We own shares of TW Common equal to approximately 100%
of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS
note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes
and TW Common shares become current tax obligations when ZENS notes are exchanged or otherwise
retired and TW Common shares are sold. A tax obligation of approximately $158 million relating to
our original issue discount deductions on the ZENS would have been payable if all of the ZENS had
been exchanged for cash on March 31, 2008. The ultimate tax obligation related to the ZENS notes
continues to increase by the amount of the tax benefit realized each year and there could be a
significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in
our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas
sales and services primarily to commercial and industrial customers and electric and gas utilities
throughout the central and eastern United States. In order to economically hedge its exposure to
natural gas prices, CES uses derivatives with provisions standard for the industry, including those
pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty
defines the amount of unsecured credit that such counterparty will extend to CES. To the extent
that the credit exposure that a counterparty has to CES at a particular time does not exceed that
credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of
the credit threshold is routinely collateralized by CES. As of March 31, 2008, the amount posted as
collateral amounted to approximately $20 million. Should the credit ratings of CERC Corp. (as the
credit support provider for CES) fall below certain levels, CES would be required to provide
additional collateral on two business days notice up to the amount of its previously unsecured
credit limit. We estimate that as of March 31, 2008, unsecured credit limits extended to CES by
counterparties aggregate $180 million; however, utilized credit capacity is significantly lower. In
addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain
an aggregate credit threshold of

$100 million based on CERC Corp.s S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades
and downgrades from this BBB rating will increase and decrease the aggregate credit threshold
accordingly.

In connection with the development of SESHs 270-mile pipeline project, CERC Corp. has
committed that it will advance funds to the joint venture or cause funds to be advanced for its 50%
share of the cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit
in an amount up to $400 million for its share of funds that have not been advanced in the event S&P
reduces CERC Corp.s bond rating below investment grade before CERC Corp. has advanced the required
construction funds. However, CERC Corp. is relieved of these commitments (i) to the extent of 50%
of any borrowing agreements that the joint venture has obtained and maintains for funding the
construction of the pipeline and (ii) to the extent CERC Corp. or its subsidiary participating in
the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed
and used for the construction of the pipeline. A similar commitment has been provided by the other
party to the joint venture. As of March 31, 2008, subsidiaries of CERC Corp. have advanced
approximately $305 million to SESH, of which $159 million was in the form of an equity contribution
and $146 million was in the form of a loan.

Cross Defaults.
Under our revolving credit facility, a payment default on, or a non-payment
default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our
significant subsidiaries will cause a default. In addition, six outstanding series of our senior
notes, aggregating $1.3 billion in principal amount as of March 31, 2008, provide that a payment
default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed
money and certain other specified types of obligations, in the aggregate principal amount of
$50 million, will cause a default. A default by CenterPoint Energy would not trigger a default
under our subsidiaries debt instruments or bank credit facilities.

Other Factors that Could Affect Cash Requirements.
In addition to the above factors, our
liquidity and capital resources could be affected by:

acceleration of payment dates on certain gas supply contracts under certain
circumstances, as a result of increased gas prices and concentration of natural gas
suppliers;



increased costs related to the acquisition of natural gas;



increases in interest expense in connection with debt refinancings and borrowings under
credit facilities;



various regulatory actions;



the ability of RRI and its subsidiaries to satisfy their obligations as the principal
customers of CenterPoint Houston and in respect of RRIs indemnity obligations to us and
our subsidiaries or in connection with the contractual obligations to a third party
pursuant to which CERC is a guarantor;

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money.
CenterPoint
Houstons credit facility limits CenterPoint Houstons debt (excluding transition bonds) as a
percentage of its total capitalization to 65%. CERC Corp.s bank facility and its receivables
facility limit CERCs debt as a percentage of its total capitalization to 65%. Our $1.2 billion
credit facility contains a debt, excluding transition bonds, to EBITDA covenant. Additionally,
CenterPoint Houston has contractually agreed that it will not issue additional first mortgage
bonds, subject to certain exceptions.

NEWACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Financial Statements for a discussion of new accounting
pronouncements that affect us.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk From Non-Trading Activities

We use derivative instruments as economic hedges to offset the commodity price exposure
inherent in our businesses. The stand-alone commodity risk created by these instruments, without
regard to the offsetting effect of the underlying exposure these instruments are intended to hedge,
is described below. We measure the commodity risk of our non-trading energy derivatives using a
sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives
measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At
March 31, 2008, the recorded fair value of our non-trading energy derivatives was a net asset of
$61 million. The net asset consisted of a net asset of less than $1 million associated with price
stabilization activities of our Natural Gas Distribution business segment and a net asset of
$60 million related to our Competitive Natural Gas Sales and Services business segment. Net assets
or liabilities related to the price stabilization activities correspond directly with net
over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the
market prices of energy commodities from their March 31, 2008 levels would have decreased the fair
value of our non-trading energy derivatives net asset by $12 million.

The above analysis of the non-trading energy derivatives utilized for commodity price risk
management purposes does not include the favorable impact that the same hypothetical price movement
would have on our physical purchases and sales of natural gas to which the hedges relate.
Furthermore, the non-trading energy derivative portfolio is managed to complement the physical
transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the
fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated
with the hypothetical changes in commodity prices referenced above is expected to be substantially
offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

As of March 31, 2008, we had outstanding long-term debt, bank loans, lease obligations,
treasury rate lock derivative instruments and obligations under our ZENS that subject us to the
risk of loss associated with movements in market interest rates.

Our floating-rate obligations aggregated $335 million at March 31, 2008. If the floating
interest rates were to increase by 10% from March 31, 2008 rates, our combined interest expense
would increase by approximately $1 million annually.

At March 31, 2008, we had outstanding fixed-rate debt (excluding indexed debt securities)
aggregating $9.2 billion in principal amount and having a fair value of $9.4 billion. These
instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to
changes in market interest rates (please read Note 9 to our consolidated financial statements).
However, the fair value of these instruments would increase by approximately $379 million if
interest rates were to decline by 10% from their levels at March 31, 2008. In general, such an
increase in fair value would impact earnings and cash flows only if we were to reacquire all or a
portion of these instruments in the open market prior to their maturity.

As of March 31, 2008, we had outstanding treasury rate locks with an aggregate notional amount
of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on
ten-year debt of 4.05%.

These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to
be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008. As of March
31, 2008, the treasury lock derivative instruments could be terminated at a cost of $16 million.
The treasury rate locks qualify as cash flow hedges under SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS No. 133), and are marked to market in our Consolidated
Balance Sheets with changes reflected in accumulated other comprehensive loss. A decrease of 10% in
the March 31, 2008 level of interest rates on 10-year U.S. treasury notes would increase the cost
of terminating the treasury rate locks outstanding at March 31, 2008 by approximately $9 million.

Upon adoption of SFAS No. 133, effective January 1, 2001, the ZENS obligation was bifurcated
into a debt component and a derivative component. The debt component of $115 million at March 31,
2008 was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings
due to changes in market interest rates. However, the fair value of the debt component would
increase by approximately $19 million if interest rates were to decline by 10% from levels at March
31, 2008. Changes in the fair value of the derivative component, a $211 million recorded liability
at March 31, 2008, are recorded in our Statements of Consolidated Income and, therefore, we are
exposed to changes in the fair value of the derivative component as a result of changes in the
underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from
March 31, 2008 levels, the fair value of the derivative component liability would increase by
approximately $3 million, which would be recorded as an unrealized loss in our Statements of
Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 21.6 million shares of TW
Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease
of 10% from the March 31, 2008 market value of TW Common would result in a net loss of
approximately $4 million, which would be recorded as an unrealized loss in our Statements of
Consolidated Income.

Item 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under
the supervision and with the participation of management, including our principal executive officer
and principal financial officer, of the effectiveness of our disclosure controls and procedures as
of the end of the period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls and procedures were
effective as of March 31, 2008 to provide assurance that information required to be disclosed in
our reports filed or submitted under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange Commissions rules and
forms and such information is accumulated and communicated to our management, including our
principal executive officer and principal financial officer, as appropriate to allow timely
decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred
during the three months ended March 31, 2008 that has materially affected, or is reasonably likely
to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy,
please read Notes 4 and 10 to our Interim Condensed Financial Statements, each of which is
incorporated herein by reference. See also Business  Regulation and   Environmental Matters
in Item 1 and Legal Proceedings in Item 3 of our 2007 Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in our 2007 Form 10-K.

Conversion of 3.75% Convertible Senior Notes due 2023.
Since February 20, 2008, we have issued
533,737 shares of our common stock upon conversion of approximately $21.4 million aggregate
principal amount of our 3.75% Convertible Senior Notes due 2023, as set forth in the table below:

Settlement Date

Principal Amount

Number of Shares

of Conversion

of Notes Converted

of Common Stock Issued

March 7, 2008

$

650,000

58,134

(1)

March 12, 2008

10,000,000

227,803

(2)

April 18, 2008

2,000

44

(2)

April 21, 2008

2,000

45

(2)

April 22, 2008

10,718,000

247,664

(2)

April 25, 2008

2,000

47

(2)

$

21,374,000

533,737

(1)

Based on terms of the notes, settled entirely through the issuance of shares except for
a payment of cash in lieu of fractional shares.

(2)

The number of shares issued in respect of any principal amount of notes converted is in
addition to payment of cash in an amount equal to the principal amount of such notes and
cash in lieu of fractional shares.

The shares of our common stock were issued solely to former holders of our 3.75% Convertible
Senior Notes due 2023 upon conversion pursuant to the exemption from registration provided under
Section 3(a)(9) of the Securities Act of 1933, as amended. This exemption is available because the
shares of our common stock were exchanged by us with our existing security holders exclusively
where no commission or other remuneration was paid or given directly or indirectly for soliciting
such an exchange.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of our shareholders held on April 24, 2008, the matters voted upon and
the number of votes cast for or against, as well as the number of abstentions and broker non-votes
as to such matters (including a separate tabulation with respect to each nominee for office), were
as stated below:

The following nominees for Class III Directors were elected to serve three-year terms expiring
at the 2011 annual meeting of shareholders (abstentions and broker non-votes were not counted):

The ratio of earnings to fixed charges for the three months ended March 31, 2007 and 2008 was
2.16 and 2.25, respectively. We do not believe that the ratios for these three-month periods are
necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our
business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange
Commission.

Item 6. EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all
exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy,
Inc.

SEC File

or

Exhibit

Registration

Exhibit

Number

Description

Report or Registration Statement

Number

Reference

3.1.1



Amended and
Restated Articles
of Incorporation of
CenterPoint Energy

CenterPoint Energys
Registration Statement on Form
S-4

3-69502

3.1

3.1.2



Articles of
Amendment to
Amended and
Restated Articles
of Incorporation of
CenterPoint Energy
dated March 27,
2002

CenterPoint Energys Form 10-K
for the year ended December 31,
2001

1-31447

3.1.1

+3.1.3



Articles of
Amendment to
Amended and
Restated Articles
of Incorporation of
CenterPoint Energy
dated April 24,
2008

3.2



Amended and
Restated Bylaws of
CenterPoint Energy

CenterPoint Energys Form 8-K
dated January 24, 2008

1-31447

3.1

3.3



Statement of
Resolution
Establishing Series
of Shares
designated Series A
Preferred Stock of
CenterPoint Energy

Pursuant to the provisions of Article 4.04 of the Texas Business Corporation Act, CenterPoint
Energy, Inc., a Texas corporation (the Company), hereby adopts the following Articles of
Amendment to its Amended and Restated Articles of Incorporation (as amended prior to the date
hereof, the Articles of Incorporation):

ARTICLE I

The name of the Company is CenterPoint Energy, Inc.

ARTICLE II

The following amendment to the Articles of Incorporation (the Amendment) was duly adopted by
the shareholders of the Company on April 24, 2008:

The Articles of Incorporation are hereby amended by deleting all of the first paragraph of
part (a) of ARTICLE V following the first sentence thereof and inserting in lieu thereof the
following:

Except as may otherwise be provided pursuant to the provisions established
by the Board of Directors with respect to any series of Preferred Stock
pursuant to Division A of Article VI of these Articles of Incorporation, at
each annual meeting of shareholders, all directors shall be elected to hold
office for a term expiring at the next succeeding annual meeting of
shareholders and until their successors have been elected and qualified;
provided, that any director elected for a longer term before the 2009 annual
meeting of shareholders shall hold office for the entire term for which he
or she was originally elected.

ARTICLE III

The Amendment has been approved in the manner required by the Texas Business Corporation Act
and the constituent documents of the Company.

IN WITNESS WHEREOF, the Company has caused these Articles of Amendment to be duly executed as
of the 24
th
day of April, 2008.

CENTERPOINT ENERGY, INC.

By:

/s/ Richard B. Dauphin

Richard B. Dauphin

Assistant Corporate Secretary

Exhibit 12

CENTERPOINT ENERGY, INCORPORATED AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
(Millions of Dollars)

Three
Months Ended
March 31,

2007

2008

Income from continuing operations

$

130

$

123

Income taxes for continuing operations

72

74

Capitalized interest

(9

)

(3

)

193

194

Fixed charges, as defined:

Interest

154

149

Capitalized interest

9

3

Interest component of rentals charged to operating expense

4

4

Total fixed charges

167

156

Earnings, as defined

$

360

$

350

Ratio of earnings to fixed charges

2.16

2.25

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;

(c)

Evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and

(d)

Disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and

5. The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and

(b)

Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting.

Date:
April 30, 2008

/s/ David M. McClanahan

David M. McClanahan
President and Chief Executive Officer

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrants other certifying officer(s) and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally
accepted accounting principles;

(c)

Evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and

(d)

Disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and

5. The registrants other certifying officer(s) and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and

(b)

Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting.

Date:
April 30, 2008

/s/ Gary L. Whitlock

Gary L. Whitlock
Executive Vice President and Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy, Inc. (the Company) on Form
10-Q for the quarter ended March 31, 2008 (the Report), as filed with the Securities and Exchange
Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to
the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company.

/s/ David M. McClanahan

David M. McClanahan

President and Chief Executive Officer

April
30, 2008

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of CenterPoint Energy, Inc. (the Company) on Form
10-Q for the quarter ended March 31, 2008 (the Report), as filed with the Securities and Exchange
Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to
the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company.

/s/ Gary L. Whitlock

Gary L. Whitlock

Executive Vice President and Chief Financial Officer

April
30, 2008

Item 1A.

Risk
Factors

We are a holding company that conducts all of our business
operations through subsidiaries, primarily CenterPoint Houston
and CERC. The following, along with any additional legal
proceedings identified or incorporated by reference in
Item 3 of this report, summarizes the principal risk
factors associated with the businesses conducted by each of
these subsidiaries:

CenterPoint
Houston may not be successful in ultimately recovering the full
value of its
true-up
components, which could result in the elimination of certain tax
benefits and could have an adverse impact on CenterPoint
Houstons results of operations, financial condition and
cash flows.

In March 2004, CenterPoint Houston filed its
true-up
application with the Texas Utility Commission, requesting
recovery of $3.7 billion, excluding interest, as allowed
under the Texas electric restructuring law. In December 2004,
the Texas Utility Commission issued the
True-Up
Order allowing CenterPoint Houston to recover a
true-up
balance of approximately $2.3 billion, which included
interest through August 31, 2004, and provided for
adjustment of the amount to be recovered to include interest on
the balance until recovery, along with the principal portion of
additional EMCs returned to customers after August 31, 2004
and in certain other respects.

CenterPoint Houston and other parties filed appeals of the
True-Up
Order to a district court in Travis County, Texas. In August
2005, that court issued its judgment on the various appeals. In
its judgment, the district court:



reversed the Texas Utility Commissions ruling that had
denied recovery of a portion of the capacity auction
true-up
amounts;



reversed the Texas Utility Commissions ruling that
precluded CenterPoint Houston from recovering the interest
component of the EMCs paid to REPs; and



affirmed the
True-Up
Order in all other respects.

The district courts decision would have had the effect of
restoring approximately $650 million, plus interest, of the
$1.7 billion the Texas Utility Commission had disallowed
from CenterPoint Houstons initial request.

CenterPoint Houston and other parties appealed the district
courts judgment to the Texas Third Court of Appeals, which
issued its decision in December 2007. In its decision, the court
of appeals:



reversed the district courts judgment to the extent it
restored the capacity auction
true-up
amounts;



reversed the district courts judgment to the extent it
upheld the Texas Utility Commissions decision to allow
CenterPoint Houston to recover EMCs paid to RRI;



ordered that the tax normalization issue described below be
remanded to the Texas Utility Commission; and



affirmed the district courts judgment in all other
respects.

CenterPoint Houston and two other parties filed motions for
rehearing with the court of appeals. In the event that the
motions for rehearing are not resolved in a manner favorable to
it, CenterPoint Houston intends to seek further review by the
Texas Supreme Court. Although we and CenterPoint Houston believe
that CenterPoint Houstons
true-up
request is consistent with applicable statutes and regulations
and accordingly that it is reasonably possible that it will be
successful in its further appeals, we can provide no assurance
as to the ultimate rulings by the courts on the issues to be
considered in the various appeals or with respect to the
ultimate decision by the Texas Utility Commission on the tax
normalization issue described below.

To reflect the impact of the
True-Up
Order, in 2004 and 2005 we recorded a net after-tax
extraordinary loss of $947 million. No amounts related to
the district courts judgment or the decision of the court
of appeals have been

recorded in our consolidated financial statements. However, if
the court of appeals decision is not reversed or modified as a
result of the pending motions for rehearing or on further review
by the Texas Supreme Court, we anticipate that we would be
required to record an additional loss to reflect the court of
appeals decision. The amount of that loss would depend on
several factors, including ultimate resolution of the tax
normalization issue described below and the calculation of
interest on any amounts CenterPoint Houston ultimately is
authorized to recover or is required to refund beyond the
amounts recorded based on the
True-up
Order, but could range from $130 million to
$350 million, plus interest subsequent to December 31,
2007.

In the
True-Up
Order the Texas Utility Commission reduced CenterPoint
Houstons stranded cost recovery by approximately
$146 million, which was included in the extraordinary loss
discussed above, for the present value of certain deferred tax
benefits associated with its former electric generation assets.
We believe that the Texas Utility Commission based its order on
proposed regulations issued by the IRS in March 2003 which would
have allowed utilities owning assets that were deregulated
before March 4, 2003 to make a retroactive election to pass
the benefits of ADITC and EDFIT back to customers. However, in
December 2005, the IRS withdrew those proposed normalization
regulations and issued new proposed regulations that do not
include the provision allowing a retroactive election to pass
the tax benefits back to customers. We subsequently requested a
PLR asking the IRS whether the Texas Utility Commissions
order reducing CenterPoint Houstons stranded cost recovery
by $146 million for ADITC and EDFIT would cause
normalization violations. In that ruling, which was received in
August 2007, the IRS concluded that such reductions would cause
normalization violations with respect to the ADITC and EDFIT. As
in a similar PLR issued in May 2006 to another Texas utility,
the IRS did not reference its proposed regulations.

The district court affirmed the Texas Utility Commissions
ruling on the tax normalization issue, but in response to a
request from the Texas Utility Commission, the court of appeals
ordered that the tax normalization issue be remanded for further
consideration. If the Texas Utility Commissions order
relating to the ADITC reduction is not reversed or otherwise
modified on remand so as to eliminate the normalization
violation, the IRS could require us to pay an amount equal to
CenterPoint Houstons unamortized ADITC balance as of the
date that the normalization violation is deemed to have
occurred. In addition, the IRS could deny CenterPoint Houston
the ability to elect accelerated tax depreciation benefits
beginning in the taxable year that the normalization violation
is deemed to have occurred. Such treatment if required by the
IRS, could have a material adverse impact on our results of
operations, financial condition and cash flows in addition to
any potential loss resulting from final resolution of the
True-Up
Order. However, we and CenterPoint Houston will continue to
pursue a favorable resolution of this issue through the
appellate or administrative process. Although the Texas Utility
Commission has not previously required a company subject to its
jurisdiction to take action that would result in a normalization
violation, no prediction can be made as to the ultimate action
the Texas Utility Commission may take on this issue on remand.

CenterPoint
Houstons receivables are concentrated in a small number of
REPs, and any delay or default in payment could adversely affect
CenterPoint Houstons cash flows, financial condition and
results of operations.

CenterPoint Houstons receivables from the distribution of
electricity are collected from REPs that supply the electricity
CenterPoint Houston distributes to their customers. Currently,
CenterPoint Houston does business with 74 REPs. Adverse economic
conditions, structural problems in the market served by ERCOT or
financial difficulties of one or more REPs could impair the
ability of these retail providers to pay for CenterPoint
Houstons services or could cause them to delay such
payments. CenterPoint Houston depends on these REPs to remit
payments on a timely basis. Applicable regulatory provisions
require that customers be shifted to a provider of last resort
if a retail electric provider cannot make timely payments.
Applicable Texas Utility Commission regulations limit the extent
to which CenterPoint Houston can demand security from REPs for
payment of its delivery charges. RRI, through its subsidiaries,
is CenterPoint Houstons largest customer. Approximately
48% of CenterPoint Houstons $141 million in billed
receivables from REPs at December 31, 2007 was owed by
subsidiaries of RRI. Any delay or default in payment could
adversely affect CenterPoint Houstons cash flows,
financial condition and results of operations.

Rate
regulation of CenterPoint Houstons business may delay or
deny CenterPoint Houstons ability to earn a reasonable
return and fully recover its costs.

CenterPoint Houstons rates are regulated by certain
municipalities and the Texas Utility Commission based on an
analysis of its invested capital and its expenses in a test
year. Thus, the rates that CenterPoint Houston is allowed to
charge may not match its expenses at any given time. In this
connection, pursuant to the Settlement Agreement, discussed in
Business  Regulation  State and
Local Regulation  Electric Transmission &
Distribution  CenterPoint Houston Rate
Agreement in Item 1 of this report, until
June 30, 2010 CenterPoint Houston is limited in its ability
to request rate relief. The regulatory process by which rates
are determined may not always result in rates that will produce
full recovery of CenterPoint Houstons costs and enable
CenterPoint Houston to earn a reasonable return on its invested
capital.

Disruptions
at power generation facilities owned by third parties could
interrupt CenterPoint Houstons sales of transmission and
distribution services.

CenterPoint Houston transmits and distributes to customers of
REPs electric power that the REPs obtain from power generation
facilities owned by third parties. CenterPoint Houston does not
own or operate any power generation facilities. If power
generation is disrupted or if power generation capacity is
inadequate, CenterPoint Houstons sales of transmission and
distribution services may be diminished or interrupted, and its
results of operations, financial condition and cash flows may be
adversely affected.

CenterPoint
Houstons revenues and results of operations are
seasonal.

A significant portion of CenterPoint Houstons revenues is
derived from rates that it collects from each retail electric
provider based on the amount of electricity it distributes on
behalf of such retail electric provider. Thus, CenterPoint
Houstons revenues and results of operations are subject to
seasonality, weather conditions and other changes in electricity
usage, with revenues being higher during the warmer months.

Rate
regulation of CERCs business may delay or deny CERCs
ability to earn a reasonable return and fully recover its
costs.

CERCs rates for its Gas Operations are regulated by
certain municipalities and state commissions, and for its
interstate pipelines by the FERC, based on an analysis of its
invested capital and its expenses in a test year. Thus, the
rates that CERC is allowed to charge may not match its expenses
at any given time. The regulatory process in which rates are
determined may not always result in rates that will produce full
recovery of CERCs costs and enable CERC to earn a
reasonable return on its invested capital.

CERCs
businesses must compete with alternative energy sources, which
could result in CERC marketing less natural gas, and its
interstate pipelines and field services businesses must compete
directly with others in the transportation, storage, gathering,
treating and processing of natural gas, which could lead to
lower prices, either of which could have an adverse impact on
CERCs results of operations, financial condition and cash
flows.

CERC competes primarily with alternate energy sources such as
electricity and other fuel sources. In some areas, intrastate
pipelines, other natural gas distributors and marketers also
compete directly with CERC for natural gas sales to end-users.
In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these
pipelines may be able to bypass CERCs facilities and
market, sell
and/or
transport natural gas directly to commercial and industrial
customers. Any reduction in the amount of natural gas marketed,
sold or transported by CERC as a result of competition may have
an adverse impact on CERCs results of operations,
financial condition and cash flows.

CERCs two interstate pipelines and its gathering systems
compete with other interstate and intrastate pipelines and
gathering systems in the transportation and storage of natural
gas. The principal elements of

competition are rates, terms of service, and flexibility and
reliability of service. They also compete indirectly with other
forms of energy, including electricity, coal and fuel oils. The
primary competitive factor is price. The actions of CERCs
competitors could lead to lower prices, which may have an
adverse impact on CERCs results of operations, financial
condition and cash flows.

CERCs
natural gas distribution and competitive natural gas sales and
services businesses are subject to fluctuations in natural gas
pricing levels, which could affect the ability of CERCs
suppliers and customers to meet their obligations or otherwise
adversely affect CERCs liquidity.

CERC is subject to risk associated with increases in the price
of natural gas. Increases in natural gas prices might affect
CERCs ability to collect balances due from its customers
and, for Gas Operations, could create the potential for
uncollectible accounts expense to exceed the recoverable levels
built into CERCs tariff rates. In addition, a sustained
period of high natural gas prices could apply downward demand
pressure on natural gas consumption in the areas in which CERC
operates and increase the risk that CERCs suppliers or
customers fail or are unable to meet their obligations.
Additionally, increasing natural gas prices could create the
need for CERC to provide collateral in order to purchase natural
gas.

If
CERC were to fail to renegotiate a contract with one of its
significant pipeline customers or if CERC renegotiates the
contract on less favorable terms, there could be an adverse
impact on its operations.

Since October 31, 2006, CERCs contract with Laclede,
one of its pipeline customers, has been terminable upon one
years prior notice. CERC has not received a termination
notice and is currently negotiating a long-term contract with
Laclede. If Laclede were to terminate this contract or if CERC
were to renegotiate this contract at rates substantially lower
than the rates provided in the current contract, there could be
an adverse effect on CERCs results of operations,
financial condition and cash flows.

A
decline in CERCs credit rating could result in CERCs
having to provide collateral in order to purchase
gas.

If CERCs credit rating were to decline, it might be
required to post cash collateral in order to purchase natural
gas. If a credit rating downgrade and the resultant cash
collateral requirement were to occur at a time when CERC was
experiencing significant working capital requirements or
otherwise lacked liquidity, CERC might be unable to obtain the
necessary natural gas to meet its obligations to customers, and
its results of operations, financial condition and cash flows
would be adversely affected.

The
revenues and results of operations of CERCs interstate
pipelines and field services businesses are subject to
fluctuations in the supply of natural gas.

CERCs interstate pipelines and field services businesses
largely rely on natural gas sourced in the various supply basins
located in the Mid-continent region of the United States. To the
extent the availability of this supply is substantially reduced,
it could have an adverse effect on CERCs results of
operations, financial condition and cash flows.

CERCs
revenues and results of operations are seasonal.

A substantial portion of CERCs revenues is derived from
natural gas sales and transportation. Thus, CERCs revenues
and results of operations are subject to seasonality, weather
conditions and other changes in natural gas usage, with revenues
being higher during the winter months.

The
actual cost of pipelines under construction and related
compression facilities may be significantly higher than
CERCs current estimates.

Subsidiaries of CERC Corp. are involved in significant pipeline
construction projects. The construction of new pipelines and
related compression facilities requires the expenditure of
significant amounts of capital, which may exceed CERCs
estimates. These projects may not be completed at the budgeted
cost, on schedule or at all. The construction of new pipeline or
compression facilities is subject to construction cost overruns
due to labor costs,

costs of equipment and materials such as steel and nickel, labor
shortages or delays, weather delays, inflation or other factors,
which could be material. In addition, the construction of these
facilities is typically subject to the receipt of approvals and
permits from various regulatory agencies. Those agencies may not
approve the projects in a timely manner or may impose
restrictions or conditions on the projects that could
potentially prevent a project from proceeding, lengthen its
expected completion schedule
and/or
increase its anticipated cost. As a result, there is the risk
that the new facilities may not be able to achieve CERCs
expected investment return, which could adversely affect
CERCs financial condition, results of operations or cash
flows.

The
states in which CERC provides regulated local gas distribution
may, either through legislation or rules, adopt restrictions
similar to or broader than those under the Public Utility
Holding Company Act of 1935 regarding organization, financing
and affiliate transactions that could have significant adverse
impacts on CERCs ability to operate.

The Public Utility Holding Company Act of 1935, to which the
Company was subject prior to its repeal in the Energy Act,
provided a comprehensive regulatory structure governing the
organization, capital structure, intracompany relationships and
lines of business that could be pursued by registered holding
companies and their member companies. Following repeal of that
Act, some states in which CERC does business have sought to
expand their own regulatory frameworks to give their regulatory
authorities increased jurisdiction and scrutiny over similar
aspects of the utilities that operate in their states. Some of
these frameworks attempt to regulate financing activities,
acquisitions and divestitures, and arrangements between the
utilities and their affiliates, and to restrict the level of
non-utility businesses that can be conducted within the holding
company structure. Additionally they may impose record keeping,
record access, employee training and reporting requirements
related to affiliate transactions and reporting in the event of
certain downgrading of the utilitys bond rating.

These regulatory frameworks could have adverse effects on
CERCs ability to operate its utility operations, to
finance its business and to provide cost-effective utility
service. In addition, if more than one state adopts restrictions
over similar activities, it may be difficult for CERC and us to
comply with competing regulatory requirements.

Risk
Factors Associated with Our Consolidated Financial
Condition

If we
are unable to arrange future financings on acceptable terms, our
ability to refinance existing indebtedness could be
limited.

As of December 31, 2007, we had $9.7 billion of
outstanding indebtedness on a consolidated basis, which includes
$2.3 billion of non-recourse transition bonds. As of
December 31, 2007, approximately $842 million
principal amount of this debt is required to be paid through
2010. This amount excludes principal repayments of approximately
$525 million on transition bonds, for which a dedicated
revenue stream exists. In addition, as of December 31,
2007, we had $535 million of outstanding 3.75% convertible
notes on which holders could exercise their conversion rights
during the first quarter of 2008 and in subsequent quarters in
which our common stock price causes such notes to be
convertible. In January and February 2008, holders of our 3.75%
convertible senior notes converted approximately
$123 million principal amount of such notes. In February
2008, we issued approximately $488 million of additional
non-recourse transition bonds. Our future financing activities
may depend, at least in part, on:



the resolution of the
true-up
components, including, in particular, the results of appeals to
the courts regarding rulings obtained to date;

our exposure to RRI in connection with its indemnification
obligations arising in connection with its separation from
us; and



provisions of relevant tax and securities laws.

As of December 31, 2007, CenterPoint Houston had
outstanding $2.0 billion aggregate principal amount of
general mortgage bonds, including approximately
$527 million held in trust to secure pollution control
bonds for which we are obligated and approximately
$229 million held in trust to secure pollution control
bonds for which CenterPoint Houston is obligated. Additionally,
CenterPoint Houston had outstanding approximately
$253 million aggregate principal amount of first mortgage
bonds, including approximately $151 million held in trust
to secure certain pollution control bonds for which we are
obligated. CenterPoint Houston may issue additional general
mortgage bonds on the basis of retired bonds, 70% of property
additions or cash deposited with the trustee. Approximately
$2.3 billion of additional first mortgage bonds and general
mortgage bonds in the aggregate could be issued on the basis of
retired bonds and 70% of property additions as of
December 31, 2007. However, CenterPoint Houston has
contractually agreed that it will not issue additional first
mortgage bonds, subject to certain exceptions.

Our current credit ratings are discussed in
Managements Discussion and Analysis of Financial
Condition and Results of Operations  Liquidity and
Capital Resources  Future Sources and Uses of
Cash  Impact on Liquidity of a Downgrade in Credit
Ratings in Item 7 of this report. These credit
ratings may not remain in effect for any given period of time
and one or more of these ratings may be lowered or withdrawn
entirely by a rating agency. We note that these credit ratings
are not recommendations to buy, sell or hold our securities.
Each rating should be evaluated independently of any other
rating. Any future reduction or withdrawal of one or more of our
credit ratings could have a material adverse impact on our
ability to access capital on acceptable terms.

As a
holding company with no operations of our own, we will depend on
distributions from our subsidiaries to meet our payment
obligations, and provisions of applicable law or contractual
restrictions could limit the amount of those
distributions.

We derive all our operating income from, and hold all our assets
through, our subsidiaries. As a result, we will depend on
distributions from our subsidiaries in order to meet our payment
obligations. In general, these subsidiaries are separate and
distinct legal entities and have no obligation to provide us
with funds for our payment obligations, whether by dividends,
distributions, loans or otherwise. In addition, provisions of
applicable law, such as those limiting the legal sources of
dividends, limit our subsidiaries ability to make payments
or other distributions to us, and our subsidiaries could agree
to contractual restrictions on their ability to make
distributions.

Our right to receive any assets of any subsidiary, and therefore
the right of our creditors to participate in those assets, will
be effectively subordinated to the claims of that
subsidiarys creditors, including trade creditors. In
addition, even if we were a creditor of any subsidiary, our
rights as a creditor would be subordinated to any security
interest in the assets of that subsidiary and any indebtedness
of the subsidiary senior to that held by us.

The
use of derivative contracts by us and our subsidiaries in the
normal course of business could result in financial losses that
could negatively impact our results of operations and those of
our subsidiaries.

We and our subsidiaries use derivative instruments, such as
swaps, options, futures and forwards, to manage our commodity,
weather and financial market risks. We and our subsidiaries
could recognize financial losses as a result of volatility in
the market values of these contracts, or should a counterparty
fail to perform. In the absence of actively quoted market prices
and pricing information from external sources, the valuation of
these financial instruments can involve managements
judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods
could affect the reported fair value of these contracts.

Risks
Common to Our Businesses and Other Risks

We are
subject to operational and financial risks and liabilities
arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and
regulations pertaining to health, safety and the environment, as
discussed in Business  Environmental
Matters in Item 1 of this report. As an owner or
operator of natural gas pipelines and distribution systems, gas
gathering and processing systems, and electric transmission and
distribution systems, we must comply with these laws and
regulations at the federal, state and local levels. These laws
and regulations can restrict or impact our business activities
in many ways, such as:



restricting the way we can handle or dispose of wastes;



limiting or prohibiting construction activities in sensitive
areas such as wetlands, coastal regions, or areas inhabited by
endangered species;



requiring remedial action to mitigate pollution conditions
caused by our operations, or attributable to former
operations; and



enjoining the operations of facilities deemed in non-compliance
with permits issued pursuant to such environmental laws and
regulations.

In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time
to:



construct or acquire new equipment;



acquire permits for facility operations;



modify or replace existing and proposed equipment; and



clean up or decommission waste disposal areas, fuel storage and
management facilities and other locations and facilities.

Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of remedial actions, and the issuance of orders
enjoining future operations. Certain environmental statutes
impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances have been
disposed or otherwise released. Moreover, it is not uncommon for
neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the
release of hazardous substances or other waste products into the
environment.

We currently have general liability and property insurance in
place to cover certain of our facilities in amounts that we
consider appropriate. Such policies are subject to certain
limits and deductibles and do not include business interruption
coverage. Insurance coverage may not be available in the future
at current costs or on commercially reasonable terms, and the
insurance proceeds received for any loss of, or any damage to,
any of our facilities may not be sufficient to restore the loss
or damage without negative impact on our results of operations,
financial condition and cash flows.

In common with other companies in its line of business that
serve coastal regions, CenterPoint Houston does not have
insurance covering its transmission and distribution system
because CenterPoint Houston believes it to be cost prohibitive.
If CenterPoint Houston were to sustain any loss of, or damage
to, its transmission and distribution properties, it may not be
able to recover such loss or damage through a change in its
regulated rates, and any such recovery may not be timely
granted. Therefore, CenterPoint Houston may not be able to
restore any loss of, or damage to, any of its transmission and
distribution properties without negative impact on its results
of operations, financial condition and cash flows.

We,
CenterPoint Houston and CERC could incur liabilities associated
with businesses and assets that we have transferred to
others.

Under some circumstances, we, CenterPoint Houston and CERC could
incur liabilities associated with assets and businesses we,
CenterPoint Houston and CERC no longer own. These assets and
businesses were previously owned by Reliant Energy, a
predecessor of CenterPoint Houston, directly or through
subsidiaries and include:



those transferred to RRI or its subsidiaries in connection with
the organization and capitalization of RRI prior to its initial
public offering in 2001; and



those transferred to Texas Genco in connection with its
organization and capitalization.

In connection with the organization and capitalization of RRI,
RRI and its subsidiaries assumed liabilities associated with
various assets and businesses Reliant Energy transferred to
them. RRI also agreed to indemnify, and cause the applicable
transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston and CERC, with respect to
liabilities associated with the transferred assets and
businesses. These indemnity provisions were intended to place
sole financial responsibility on RRI and its subsidiaries for
all liabilities associated with the current and historical
businesses and operations of RRI, regardless of the time those
liabilities arose. If RRI were unable to satisfy a liability
that has been so assumed in circumstances in which Reliant
Energy and its subsidiaries were not released from the liability
in connection with the transfer, we, CenterPoint Houston or CERC
could be responsible for satisfying the liability.

Prior to the distribution of our ownership in RRI to our
shareholders, CERC had guaranteed certain contractual
obligations of what became RRIs trading subsidiary. Under
the terms of the separation agreement between the companies, RRI
agreed to extinguish all such guaranty obligations prior to
separation, but at the time of separation in September 2002, RRI
had been unable to extinguish all obligations. To secure CERC
against obligations under the remaining guaranties, RRI agreed
to provide cash or letters of credit for the benefit of CERC,
and undertook to use commercially reasonable efforts to
extinguish the remaining guaranties. In February 2007, we and
CERC made a formal demand on RRI in connection with one of the
two remaining guaranties under procedures provided by the Master
Separation Agreement, dated December 31, 2000, between
Reliant Energy and RRI. That demand sought to resolve a
disagreement with RRI over the amount of security RRI is
obligated to provide with respect to this guaranty. In December
2007, we, CERC and RRI amended the agreement relating to the
security to be provided by RRI for these guaranties, pursuant to
which CERC released the $29.3 million in letters of credit
RRI had provided as security, and RRI agreed to provide cash or
new letters of credit to secure CERC against exposure under the
remaining guaranties as calculated under the new agreement if
and to the extent changes in market conditions exposed CERC to a
risk of loss on those guaranties.

The remaining exposure to CERC under the guaranties relates to
payment of demand charges related to transportation contracts.
The present value of the demand charges under those
transportation contracts, which will be effective until 2018,
was approximately $135 million as of December 31,
2007. RRI continues to meet its obligations under the contracts,
and we believe current market conditions make those contracts
valuable in the near term and that additional security is not
needed at this time. However, changes in market conditions could
affect the value of those contracts. If RRI should fail to
perform its obligations under the contracts or if RRI should
fail to provide security in the event market conditions change
adversely, our exposure to the counterparty under the guaranty
could exceed the security provided by RRI.

RRIs unsecured debt ratings are currently below investment
grade. If RRI were unable to meet its obligations, it would need
to consider, among various options, restructuring under the
bankruptcy laws, in which event RRI might not honor its
indemnification obligations and claims by RRIs creditors
might be made against us as its former owner.

Reliant Energy and RRI are named as defendants in a number of
lawsuits arising out of energy sales in California and other
markets and financial reporting matters. Although these matters
relate to the business and operations of RRI, claims against
Reliant Energy have been made on grounds that include the effect
of RRIs financial results on Reliant Energys
historical financial statements and liability of Reliant Energy
as a controlling shareholder of RRI. We or CenterPoint Houston
could incur liability if claims in one or more of these lawsuits
were

successfully asserted against us or CenterPoint Houston and
indemnification from RRI were determined to be unavailable or if
RRI were unable to satisfy indemnification obligations owed with
respect to those claims.

In connection with the organization and capitalization of Texas
Genco, Texas Genco assumed liabilities associated with the
electric generation assets Reliant Energy transferred to it.
Texas Genco also agreed to indemnify, and cause the applicable
transferee subsidiaries to indemnify, us and our subsidiaries,
including CenterPoint Houston, with respect to liabilities
associated with the transferred assets and businesses. In many
cases the liabilities assumed were obligations of CenterPoint
Houston and CenterPoint Houston was not released by third
parties from these liabilities. The indemnity provisions were
intended generally to place sole financial responsibility on
Texas Genco and its subsidiaries for all liabilities associated
with the current and historical businesses and operations of
Texas Genco, regardless of the time those liabilities arose. In
connection with the sale of Texas Gencos fossil generation
assets (coal, lignite and gas-fired plants) to Texas Genco LLC,
the separation agreement we entered into with Texas Genco in
connection with the organization and capitalization of Texas
Genco was amended to provide that all of Texas Gencos
rights and obligations under the separation agreement relating
to its fossil generation assets, including Texas Gencos
obligation to indemnify us with respect to liabilities
associated with the fossil generation assets and related
business, were assigned to and assumed by Texas Genco LLC. In
addition, under the amended separation agreement, Texas Genco is
no longer liable for, and we have assumed and agreed to
indemnify Texas Genco LLC against, liabilities that Texas Genco
originally assumed in connection with its organization to the
extent, and only to the extent, that such liabilities are
covered by certain insurance policies or other similar
agreements held by us. If Texas Genco or Texas Genco LLC were
unable to satisfy a liability that had been so assumed or
indemnified against, and provided Reliant Energy had not been
released from the liability in connection with the transfer,
CenterPoint Houston could be responsible for satisfying the
liability.

We or our subsidiaries have been named, along with numerous
others, as a defendant in lawsuits filed by a large number of
individuals who claim injury due to exposure to asbestos. Most
claimants in such litigation have been workers who participated
in construction of various industrial facilities, including
power plants. Some of the claimants have worked at locations we
own, but most existing claims relate to facilities previously
owned by our subsidiaries but currently owned by Texas Genco
LLC, which is now known as NRG Texas LP. We anticipate that
additional claims like those received may be asserted in the
future. Under the terms of the arrangements regarding separation
of the generating business from us and its sale to Texas Genco
LLC, ultimate financial responsibility for uninsured losses from
claims relating to the generating business has been assumed by
Texas Genco LLC and its successor, but we have agreed to
continue to defend such claims to the extent they are covered by
insurance maintained by us, subject to reimbursement of the
costs of such defense by Texas Genco LLC.